Comments on Mar 13 meeting discussion and Track 1 Straw Proposal and Track 2 Issue Paper

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

2. Please submit your organization’s overall comments on Track 1.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

6. Please submit your organization’s overall comments on Track 2.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the Demand and Distributed Energy Market Integration (DDEMI) Track 1 Straw Proposal and Track 2 Issue Paper. CalCCA supports the Track 1 Straw Proposal to allow exports from individual customer meters under the modified Proxy Demand Response (mPDR) construct, with the following clarifications:

• The mPDR model should be available under all applicable Performance Evaluation Methodologies (PEM);
• The DR Providers (DRP) should determine how to allocate exports across customers participating in the aggregation;
• DRPs should be able to create aggregations consisting of exporting and non-exporting Demand Response (DR) and distributed energy resources (DER) within a sub-load aggregation point (sub-LAP), to maximize exported energy; and
• Individual customer resources that are capable of exporting energy will interconnect using a Rule 21 export agreement.

CalCCA does not yet take a position on the Track 2 Issue Paper. Before taking a position, CalCCA requires additional information about the applicability and details of the Issue Paper. The California Independent System Operator (CAISO) should therefore modify the Issue Paper to:

• Clarify that the large loads topic applies to both resources within the CAISO Balancing Area Authority (BAA), as well as those in non-CAISO BAAs;
• Consider how large loads with DR capability located in the CAISO BAA should be modeled to ensure their demand reduction capabilities are accurately represented; and
• Clarify how the DDEMI stakeholder process and the Large Loads stakeholder process interact.

Finally, CalCCA recommends modifications to the Coordination Framework and DDEMI Scoping Issues topics in the Track 2 Issue Paper. In summary, the CAISO should:

• Include community choice aggregator (CCA) representatives in its coordination framework efforts, since CCAs comprise roughly one-third of the CAISO load and manage significant DR and DERs via their customer programs;
• Clarify what it considers to be ‘flexible load’ in the context of the near-term proposal, scheduled to be addressed in the third quarter of 2026; and
• Modify the Straw Proposal and Issue Paper to include a discussion of device-level measurement, which was discussed at length during the 2025 DDEMI Working Group (WG) efforts in 2025 but was not addressed in the Straw Proposal or Issue Paper.

2. Please submit your organization’s overall comments on Track 1.

CalCCA supports the Track 1 Straw Proposal’s mPDR model to enable exports from the individual customer meter, with clarifications discussed in responses to questions 3, 4, and 5. The mPDR framework would provide DRPs with incentives to create aggregations to maximize exports within each sub-LAP. The Straw Proposal would modify PEMs to allow individual resources, subject to their Rule 21 export agreements, to receive credit for exports that would otherwise be zeroed out under the current PDR framework. The mPDR would allow cumulative exports up to the total load of the entire aggregation and encourage DRPs to create portfolios of exporting and non-exporting resources to maximize net export credits.

Allowing PDR exports will accurately reflect resource capabilities, minimize barriers to participation, and offer both reliability and cost-efficiency benefits. Expanding the pool of dependable capacity using the mPDR model will provide additional reliability during times of system stress and improve price formation by increasing the amount of demand that can respond to market price signals. The mPDR model would also enable a pathway for CCAs and other load-serving entities (LSE) to receive resource adequacy (RA) credit for the additional energy exported, thereby lowering customer costs.[1]

[1]             In the CPUC’s recently opened DR (R.25-09-004) and RA (R.25-10-003) proceedings, in which many stakeholders, including CalCCA, asked the CPUC to develop a qualifying capacity (QC) methodology for PDRs capable of exports. RA participation necessitates both a QC methodology and a market participation model. The CAISO and CPUC should coordinate to ensure that both entities address the issues within their separate jurisdictional responsibilities, thereby supporting full RA and energy market participation of PDRs with export capabilities. See California Community Choice Association’s Reply Comments on the Order Instituting Rulemaking to Enhance Demand Response in California, Rulemaking (R.) 25-09-004 (Dec. 1, 2025), at 11-12: https://cal-cca.org/wp-content/uploads/2025/12/Reply-Comments-on-the-OIR-to-Enhance-Demand-Response-in-California-12-01-25.pdf.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

The Straw Proposal to allow exports from individual customer resources, up to the total load of each DRP’s sub-LAP aggregation, should apply to all PEMs and not be limited to the Meter Generator Output (MGO) PEM. The CAISO does not provide any compelling reason to limit the applicability of the mPDR model to the MGO PEM. Additionally, the Straw Proposal correctly notes that the MGO PEM is rarely used, thereby limiting the change's potential impact.[2] Restricting the change to just the MGO would discourage participation and limit the potential benefits of market participation. The CAISO should therefore modify the Straw Proposal to allow the mPDR model to be used by resources using all PEMs, rather than just the MGO PEM.

[2]           Straw Proposal and Issue Paper, at 11.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

The DRP should be allowed to determine how individual end-use customers within an mPDR aggregation are credited with exports. Since the DRP will be responsible for creating aggregations of exporting and non-exporting customer resources, it should be allowed to determine how to allocate credits to encourage participation and maximize benefits for all participating customers. If the goal of the mPDR model is to increase market participation by behind-the-meter (BTM) DERs that can reduce peak capacity, DRPs are better positioned to design compensation mechanisms for participating resources to achieve this objective.

CCAs currently manage a variety of DR and DER programs, including several that offer virtual power plant (VPP) programs.[3] These programs often encompass a variety of DER and flexible demand resources, including solar, energy storage, electric vehicle charging, smart thermostats, heat pumps, and other controllable smart appliances. These programs are designed to accomplish a variety of objectives, including reducing demand during peak times, providing customer bill savings, providing reliability, encouraging electrification, and reducing greenhouse gas emissions. CCAs must be able to design programs, including the allocation of exported energy from DERs participating in an mPDR aggregation, designed to benefit the customers and communities they serve. The CAISO should therefore allow CCAs and other DRPs to determine how individual customers are compensated for participation in an mPDR aggregation.

[3]             See, e.g., Peninsula Clean Energy, Silicon Valley Clean Energy Jointly Launch Demand Flexibility Initiatives (Nov. 3, 2025): https://svcleanenergy.org/news/peninsula-clean-energy-silicon-valley-cleanenergy-jointly-launch-demand-flexibility-initiatives/; MCE Unveils Plans for Virtual Power Plant to Benefit Disadvantaged Richmond Residents and Business (June 21, 2022): https://mcecleanenergy.org/mce-unveilsplans-for-virtual-power-plant-to-benefit-disadvantaged-richmond-residents-and-businesses/; Ava Community Energy Announces Ambitious Virtual Power Plant Initiative to Help its 2M Customers Optimize Their Energy Investments While Relieving Stress on the Grid (Apr. 24, 2025): https://avaenergy.org/news/ava-announcesvirtual-power-plant-initiative/.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

The CAISO should clarify the Straw Proposal to confirm that DRPs can create aggregations consisting of exporting and non-exporting DR and DERs within a sub-LAP to maximize exported energy. While only customers with a Rule 21 export agreement will be eligible to export under the mPDR mechanism, aggregators are responsible for creating a portfolio of DER/DR resources within a sub-LAP to optimize export credits under the mPDR construct. The CAISO’s Straw Proposal should therefore ensure that DRPs are able to create aggregations consisting of exporting and non-exporting, as long as only Rule 21 customers are eligible to export.

6. Please submit your organization’s overall comments on Track 2.

CalCCA recommends that the CAISO clarify the Track 2 Issue Paper in three ways to provide additional information regarding the Issue Paper’s applicability and details. First, the Issue Paper should be expanded to consider flexible resource participation options for large loads located in both CAISO BAAs and non-CAISO BAAs. While the Issue Paper appears to discuss large loads in the context of the non-CAISO Western Energy Imbalance Market (WEIM) and extended day-ahead market (EDAM) footprint, the CAISO-BAA is also forecast to receive a significant number of large-load interconnections in the coming years.[4] CalCCA agrees with the CAISO’s approach to “not presume[e] that all large loads are flexible or [that they] should automatically be treated as supply-side resources” and instead “create a set of participation options that accommodate a range of capabilities and business models.”[5] The CAISO should discuss further with stakeholders how large loads customers plan to participate in demand flexibility to inform participation options.

Second, the CAISO should also consider how to model large loads with DR capability within the CAISO BAA to ensure their load-reduction capability is accurately represented. Most loads participating in the CAISO DR market models are modeled at the sub-LAP level. Using 24 sub-LAPs to establish the boundaries for DR resource aggregations has worked well for the CAISO thus far, as loads participating in DR aggregations have historically been smaller and more dispersed across the sub-LAP. However, as large loads like data centers increasingly interconnect, the CAISO should consider how DR for large loads may need to be modeled differently to ensure the CAISO’s market model accurately reflects how large loads’ DR capabilities will impact pricing, dispatch, congestion, and system reliability. For example, data centers with DR may be more accurately reflected via a custom-LAP where the data center load is not lumped into a sub-LAP with other smaller, more dispersed loads.

Third, the CAISO should clarify the stakeholder process[es] that will be used to discuss large load flexibility issues. CalCCA understands that these issues may be considered in the CAISO’s upcoming Large Loads initiative. Thus far, the Large Loads initiative has focused on technical requirements and standards, but will soon evolve to also consider other policy-related questions, such as co-located loads and generation, transmission service offerings, and cost-allocation.[6] The CAISO should clarify how the DDEMI and Large Loads initiatives will interact and where issues related to large-load flexibility will be addressed.

[4]             Large Loads Technical Requirements (Mar. 10, 2026), at 6: https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-Large-Loads-Technical-Requirements-Mar-10-2026.pdf.

[5]           Issue Paper, at 22.

[6]           Large Loads Technical Requirements, at 7.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

CalCCA has no comments at this time.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

CalCCA has no comments at this time.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

CalCCA has no comments at this time.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

CalCCA has no comments at this time.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

CalCCA has no comments at this time.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

CalCCA recommends that the CAISO include CCA representatives in the “Related Issues – Coordination Framework” effort. While CCAs do not own or operate grid infrastructure, they comprise roughly one-third of the CAISO load and manage DERs and flexible loads via programs and, increasingly, VPP software platforms. CCAs can therefore play an important role in supporting accurate short-term forecasting, strengthening situational awareness, and optimizing and supporting reliable grid operations via flexible loads and resources, and should be included in these efforts.

The CAISO should also clarify the term ‘flexible load,’ specifically what it includes in the context of the Near-Term Proposal for Q3 of 2026. The Straw Proposal and Issue Paper includes discussions about a variety of flexible loads, including BTM DERs and DR, large loads interconnected at both the distribution and transmission level, and Participating Loads such as pumped storage. CalCCA is unsure what the CAISO intends to include in the scope of the Near-Term Proposal and recommends that the CAISO define which types of flexible loads are under consideration for this effort.

Finally, the CAISO should modify the Straw Proposal and Issue Paper to include the exploration of device-level measurement in the mPDR Straw Proposal and in future PEM discussions. Device-level measurement was discussed at length during the 2025 DDEMI WG meetings, but is not specifically included in any near-, medium-, or long-term proposals. The November 26, 2025, DDEMI WG Discussion Paper identified the lack of device-level measurement in developing PEM baselines, including the requirement for revenue-grade metering, as a barrier to participation for many resource types.[7]

Device-level measurement could enable participation of a variety of resources that lack revenue-grade metering, such as smart thermostats and appliances, in mPDR aggregations. This could further enhance a DRP’s ability to maximize exports by allowing it to combine exporting DERs with non-exporting, load-reducing flexible resources. The CAISO should therefore modify the Straw Proposal and Issue Paper to incorporate the exploration of device-level metering as a component of the mPDR proposal and any future discussion of PEMs.

[7]             See DDEMI WG Discussion Paper (Nov. 26, 2025): https://stakeholdercenter.caiso.com/InitiativeDocuments/Discussion-Paper-Demand-and-Distributed-Energy-Market-Integration-Nov-26-2025.pdf.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

The California Department of Water Resources – State Water Project (CDWR-SWP) appreciates the work that CAISO and other stakeholders put in over the past year in getting the DDEMI initiative to this beginning phase of policy development with the release of the Straw Proposal and Issue Paper. CDWR-SWP looks forward to further collaboration as work progresses through Tracks 1 & 2, and in the working groups focused on Real-Time Bidding for Flexible Load and Pumped Storage.

However, CDWR-SWP would have preferred to see the DDEMI Discussion Paper topic Enhancing Demand Flexibility Market Options’ Problem Statements 7, 8, & 9 on real-time load bidding[1] more clearly reflected in CAISO’s issue paper or work tracks, and given greater consideration and priority. These problem statements represent significant effort and input from CDWR-SWP and other stakeholders during the 2025 workshop process.

While CDWR-SWP appreciates CAISO’s plan to address Real-Time Bidding for Flexible Load and Pumped Storage in Q3 2026 through dedicated working groups, we strongly encourage CAISO to build on the work and problem statements already developed by CDWR-SWP and other stakeholders.

It is important that the Q3 2026 working group effort does not restart or duplicate prior discussions, but instead meaningfully advances them. Specifically, CDWR-SWP recommends that CAISO further develop a structured framework for real-time load bidding based on these existing problem statements—similar to the approach taken for Large Load in Track 2—allowing stakeholders to have more substantive and focused discussions during the working groups that help advance real-time load bidding.

[1] California Independent System Operator. Discussion Paper: Demand and Distributed Energy Market Integration. 26 Nov. 2025, p 7. https://stakeholdercenter.caiso.com/InitiativeDocuments/Discussion-Paper-Demand-and-Distributed-Energy-Market-Integration-Nov-26-2025.pdf

2. Please submit your organization’s overall comments on Track 1.

No comment.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

No comment. 

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

No comment.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

No comment. 

6. Please submit your organization’s overall comments on Track 2.

CDWR-SWP is encouraged to see that CAISO plans to evaluate additional demand flexibility enhancements to support demand response and large load participation across the WEIM and EDAM footprints. CDWR-SWP also appreciates CAISO’s efforts to examine participation pathways for large loads—some of which may be capable of providing operational flexibility—and to develop a decision framework to help determine whether such resources should be modeled on the supply side or demand side.

With respect to the supply-side modeling options described in the Straw Proposal and Issue Paper Figure 2: Large Load Decision Tree[1], CDWR-SWP recommends that CAISO also consider further exploration of Participating Load models. The problem statements under Enhancing Demand Flexibility Options in the Discussion Paper outline potential enhancements to Participating Load models that could be further developed in Track 2. Specifically, problem statement 7 on preserving current key features of Participating Load while enabling the ability to submit bids in the real-time market (RTM), problem statement 8 on giving Participating Load the ability to submit energy bids in RTM to increase and decrease consumption, and problem statement 9 on implementing the ability to bid at discrete levels without uninstructed deviation costs.

Accordingly, CDWR-SWP requests that CAISO include Participating Load models in the Straw Proposal and incorporate them into the decision framework for large load participation options, in addition to the PDR, PL, DERA, and RDRR models currently identified.

[1] California Independent System Operator. Straw Proposal and Issue Paper: Demand and Distributed Energy Market Integration. 11 March 2026, p 24. https://stakeholdercenter.caiso.com/InitiativeDocuments/Straw-Proposal-and-Issue-Paper-Demand-and-Distributed-Energy-Market-Integration-Mar-13-2026.pdf

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

No comment.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

No comment. 

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

No comment. 

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

No comment.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

No comment. 

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

No comment. 

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

CEDMC appreciates the March 13 discussion and strongly supports the Track 1 Straw Proposal to remove the existing requirement for Scheduling Coordinators to set customer load meter data during DR dispatch intervals to a minimum of zero during periods when those cusotmers may be exporting energy onto the distribution system. 

2. Please submit your organization’s overall comments on Track 1.

CEDMC supports the Track 1 Straw Proposal but would like CAISO to take a broader/more expansive view to ensure there are no sub-LAP level exports. 

• Good: Resource ID level (each resource can't be negative)
• Better: DR Provider level (the total across all of RH's or Leap's resources can't be negative)
• Best: Sub-LAP level (as long as the sub-LAP in aggregate isn't negative, all exports can be counted)

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

If applying the proposed changes to all PEMs allows aggregators to use the PEM that fits their resource, CEDMC supports this additional flexibility.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

CEDMC does not have comments at this time.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

CEDMC does not have comments at this time.

6. Please submit your organization’s overall comments on Track 2.

CEDMC does not have comments at this time.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

CEDMC does not have comments at this time.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

CEDMC does not have comments at this time.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

CEDMC does not have comments at this time. 

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

CEDMC does not have comments at this time. 

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

CEDMC does not have comments at this time. 

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

CEDMC does not have additional comments at this time. 

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Comments on Demand and Distributed Energy Market Integration Straw Proposal and Issue Paper

Department of Market Monitoring

March 27, 2026

Summary

The Department of Market Monitoring (DMM) appreciates the opportunity to comment on the Demand and Distributed Energy Market Integration - Track 1: Straw Proposal: End-User Exports in Demand Response Performance Measurement and Track 2: Demand Flexibility Enhancements dated March 13, 2026.[1] DMM supports limiting the scope of the DDEMI process to focus on near-term enhancements that improve existing processes and extend market demand response (DR) participation functionality to the Western Energy Imbalance Market (WEIM).[2]  

For Track 1, DMM recommends the ISO ensure current rules and existing performance evaluation methodologies are retained and prevent baseline manipulation. Further, DMM continues to recommend the ISO ensure DR resources appropriately use baseline calculation methodologies to reflect the performance of the resource. We also note DMM’s previous support for extending access to the DR model to WEIM entities and the removal of the reliability demand response resource (RDRR) size limits.[3]^,[4] We also note the importance of transparency provided by the demand response registration system (DRRS) or similar system that may be used by WEIM DR resources, and propose enhancements to the existing DRRS to improve monitoring of DR resources in CAISO.

Comments

The ISO is proposing a small change to remove the existing requirements for scheduling coordinators to set the load meter data of individual customers within an aggregated DR resource to a minimum of zero during DR dispatch. Simultaneously, the ISO is proposing to introduce a new minimum that explicitly prohibits the aggregated output of customers comprising a DR resource from being less than zero, to prevent “negative” generation from supply-side DR resources.

The removal of the minimum for individual customers will allow the ISO markets to better account for energy produced by customers that are already approved for export onto the distribution system. The aggregate limitation of DR in the ISO market ensures resources will continue to be load curtailment and preserve market topology to limit unmodeled congestion.

DMM supports the ISO’s proposal to improve modeling of DR resources by recognizing that some customers are currently approved to export onto the distribution system from their utility distribution company (UDC) in such a way that protects the safety and reliability of the system.[5] However, DMM recommends the ISO ensure the rules and agreements for exporting resources do not allow customers to circumvent the interconnection queue process for generating technologies. The concern arises where generation technologies could potentially use the demand response participation pathway to avoid interconnection queue review, system impact studies, and cost responsibility applicable to generation resources.

Further, DMM notes that the proposal removes the minimum limit to all performance evaluation methodologies and customer load baseline calculations. Since the underlying resources may still be used when not economically dispatched, performance should be evaluated by comparing the dispatch resulting from a market signal and schedule to a robust counterfactual that incorporates regular customer behavior. When allowing resources to export to the distribution system, DMM highlights it is important that baselines must continue to be calculated to reflect expected typical customer behavior in the absence of any market dispatch.

DMM has previously recommended the ISO consider enhancements to the counterfactual of existing baselines, and will continue to monitor resource behavior if the straw proposal in Track 1 is implemented.[6]^,[7] Lastly, DMM encourages the ISO and stakeholders work to ensure developments in Track 1 improve resource availability and performance when allowing customers to export to the distribution system.[8]

Finally, in considering Track 2 of the policy development process, DMM notes the ISO should continue to require resources to provide information for each customer to the DR registration system (DRRS) to facilitate monitoring, or a similar database if the DR resources are in the WEIM. Additionally, DMM recommends the ISO work with partner agencies to provide information on each customer’s expected load flexibility in MW (or kW) and additional meta data—such as customer type, end-use equipment, and control strategy—and make it available to DMM for continued monitoring.

[1] Demand and Distributed Energy Market Integration Track 1: Straw Proposal: End-User Exports in Demand Response Performance Measurement Track 2: Demand Flexibility Enhancements, California ISO, March 13, 2026: https://stakeholdercenter.caiso.com/InitiativeDocuments/Straw-Proposal-and-Issue-Paper-Demand-and-Distributed-Energy-Market-Integration-Mar-13-2026.pdf

[2] The Western Energy Imbalance Market (WEIM) includes balancing authorities that are in the Western Energy Imbalance Market (WEIM) and the forthcoming Extended Day-Ahead Market (EDAM).

[3] Comments on Demand and Distributed Energy Market Integration Working Group Discussion Paper, July 11, 2025: https://www.caiso.com/documents/dmm-comments-on-demand-and-distributed-energy-market-integration-jun-13-2025-working-group-discussion-paper-jul-7-2025.pdf

[4] Comments on Demand and Distributed Energy Market Integration, Department of Market Monitoring, February 21, 2025: https://www.caiso.com/documents/dmm-comments-on-demand-and-distributed-energy-market-integration-feb-05-2025-working-group-feb-21-2025.pdf

[5] The interconnection agreements would be analogous to a Rule 21 export agreement for California Public Utilities Commission jurisdictional utilities.

[6] Comments on Demand and Distributed Energy Market Integration Working Group, November 6, 2025: https://www.caiso.com/documents/dmm-comments-on-demand-and-distributed-energy-market-integration-working-group-nov-06-2025.pdf

[7] Comments on Demand and Distributed Energy Market Integration, Department of Market Monitoring, May 1, 2025: https://www.caiso.com/documents/dmm-comments-on-demand-and-distributed-energy-market-integration-apr-07-2025-working-group-may-01-2025.pdf

[8] Comments on Resource Adequacy Modeling and Program Design Track 2 – RAAIM Reform Presentation, Department of Market Monitoring, March 23, 2026, p 7: https://www.caiso.com/documents/dmm-comments-on-rampd-track-2-raaim-reform-mar-02-2026-input-session-ahead-of-straw-proposal-mar-23-2026.pdf

2. Please submit your organization’s overall comments on Track 1.

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

6. Please submit your organization’s overall comments on Track 2.

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

The California Large Energy Consumers Association (CLECA)^[1] appreciates the opportunity to comment on the Demand and Distributed Energy Market Integration (DDEMI) Track 1 Straw Proposal and the Track 2 Issue Paper. CLECA supports the Track 1 Straw Proposal on end-user exports and offers the following comments on the Track 2 issues.

CLECA represents large load industrial customers and participated consistently and actively in this process on that basis. CLECA presented on reliability demand response resource (RDRR) issues at Working Group Session 6,^[2] alongside SCE as one of two stakeholder presenters on RDRR. Large load stakeholders are directly engaged in this process and merit fuller consideration within the scope of this initiative. CLECA requests CAISO clarify its statement that “the DDEMI working group had limited direct engagement with large load stakeholders.”^[3] That statement does not reflect CLECA’s experience with and active engagement in the DDEMI working group and warrants revision.

Under the current proposal, CAISO has placed RDRR minimum on-time (MOT) and startup costs among longer-term topics not being advanced at this time. By contrast, the only RDRR issue from Problem Statement 3 selected for near-term advancement is the 100 MW discrete dispatch limit, which was raised by investor-owned utilities (IOUs). CLECA does not oppose that reform, but the current scope fails to address the RDRR issues raised by stakeholders representing large industrial loads.

CLECA is very concerned that the Track 2 scope fails to adequately address RDRR issues that were proposed and prioritized by stakeholders in the 2024 Catalog process and further scoped during the DDEMI Working Group process. CLECA proposed RDRR reforms as priorities for current and prospective RDRR participants that would improve dispatch accuracy. However, the current proposal does not include any of those issues for near-term or mid-term advancement. Specifically, the Issue Paper does not advance the priority issues CLECA identified in its comments on the DDEMI Discussion Paper:^[4]

• Problem Statement 3.1: Inclusion of startup costs for RDRRs
• Problem Statement 3.2: Revision of the RDRR minimum MOT requirement

CAISO’s proposal to forgo MOT reform has not been adequately justified. As CLECA has repeatedly explained, the current one-hour MOT does not reflect the operating realities of many large industrial loads, which cannot cycle on and off over short timeframes. The current MOT may discourage participation by customers capable of providing reliable, predictable demand response capacity. Continued deferral of MOT reform is therefore difficult to reconcile with DDEMI’s objective of enhancing demand flexibility. In the DDEMI Discussion Paper, CAISO staff stated that a more accurate representation of MOTs would be “operationally valuable to the ISO” and that recognizing a longer MOT in Real-Time Pre-Dispatch (RTPD) would be “relatively straightforward” to implement.^[5]

Despite this record, CAISO now characterizes MOT reform as a longer-term topic that may not be feasible without fundamental reforms to the Short-Term Unit Commitment (STUC) process. CLECA's Working Group Session 10 comments proposed a phased approach intended to address exactly that concern. Under a phased approach, CAISO would first expand the allowable MOT to align with the RTPD horizon of seven intervals, which staff indicated would not require STUC modifications, and then consider further alignment with the STUC horizon as implementation issues are resolved.^[6]

This proposal already reflects a compromise from CAISO’s prior work on this issue. In January 2024, CAISO published a Final Proposal that would have removed the one-hour MOT restriction and allowed a combined start-up time and minimum on-time of up to 255 minutes, aligned with the STUC horizon.^[7] That January 2024 proposal included draft tariff language and was scheduled for Board and WEIM Governing Body approval in February 2024. The underlying policy work was complete, and CAISO staff stated the initiative’s purpose was to “provide operational benefit by more accurately reflecting RDRRs’ minimum on time in the markets during stressed conditions.”^[8] However, the effort was paused due to temporary uncertainty about how CAISO dispatch considered MOT, an issue that the DDEMI Working Group process has since clarified.

Given this history, CLECA strongly encourages CAISO to expand the MOT to the RTPD horizon with near-term implementation, while deferring potential evaluation of STUC changes to a future process. This proposal seeks less than what CAISO was prepared to implement two years ago.

CLECA’s responses to the remaining questions below address the specific issues raised in the Straw Proposal and Issue Paper. At the same time, CLECA respectfully emphasizes that the exclusion of its RDRR priorities, particularly MOT reform, is highly problematic and strongly encourages CAISO to revise the scope to include these priorities before issuing the Draft Final Proposal.

[1] CLECA member companies produce goods essential for daily life, including critical infrastructure, oxygen for hospitals, and food distribution. CLECA members represent the steel, cement, industrial and medical gas, beverage, minerals processing, cold storage, and pipeline transportation industries. Their aggregate electric demand is about 500 Megawatts, which is equivalent to the electricity consumption of approximately 470,000 average California households. CLECA members are large, high load factor and high voltage industrial electric customers in California for whom the price of electricity is essential to their competitiveness and for whom the reliability of electricity service is critically important. For both reasons, CLECA member companies have participated for decades in the Base Interruptible Program (BIP), providing reliability demand response to the grid in times of need. (For more information, please go to CLECA.org).

[2] California Large Energy Consumers Association (CLECA), Working Group Session 6: Problem Statements and Stakeholder Presentations (July 8, 2025), available at: https://stakeholdercenter.caiso.com/InitiativeDocuments/CLECA-Presentation-Demand-and-Distributed-Energy-Market-Intgeration-Jul8-2025.pdf

[3] California Independent System Operator, Demand and Distributed Energy Market Integration Working Group Straw Proposal and Issue Paper, page 22 (March 11, 2026), available at: https://stakeholdercenter.caiso.com/InitiativeDocuments/Straw-Proposal-and-Issue-Paper-Demand-and-Distributed-Energy-Market-Integration-Mar-13-2026.pdf

[4] California Large Energy Consumers Association (CLECA), Comments on Final Discussion Paper (Dec. 12, 2025), available at: https://stakeholdercenter.caiso.com/Comments/AllComments/89fdaba8-1acf-4d66-bb37-182547f60193#org-38616ec9-8b05-46cb-8937-bb2a51b95f49

[5] California Independent System Operator, Demand and Distributed Energy Market Integration Working Group Discussion Paper, Page 21, (Nov. 26, 2025),available at https://stakeholdercenter.caiso.com/InitiativeDocuments/Discussion-Paper-Demand-and-Distributed-Energy-Market-Integration-Nov-26-2025.pdf

[6] California Large Energy Consumers Association (CLECA), Comments on Working Group Session 10 (Nov. 4, 2025), available at: https://stakeholdercenter.caiso.com/Comments/AllComments/2f80e46e-e576-427a-b671-f2a9b4ae390a#org-fc052b3d-b883-4c78-b26a-d09bda798fb4

[7] California Independent System Operator, Reliability Demand Response Resource Minimum On Time, Final Proposal, (Jan. 18, 2024), available at https://www.caiso.com/documents/final-proposal-reliability-demand-response-resource-minimum-on-time-jan18-2024.pdf

[8] Id., at page 2.

2. Please submit your organization’s overall comments on Track 1.

CLECA supports the general direction of the Track 1 Straw Proposal to remove the customer-level zeroing requirement and replace it with a resource-level aggregate floor. The current zeroing rule limits the potential capability of demand response resources. Correcting this accounting barrier would allow demand response providers to offer the full capability of their resources in CAISO markets, increasing resource availability during periods of system need. 

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

CLECA supports applying the proposed change to all performance evaluation methodologies (PEMs), not just the metering generator output (MGO) methodology, since the underlying problem exists across all methodologies.

The CAISO tariff requires zeroing out exporting intervals for the MGO PEM, while a broader prohibition on reflecting exports applies across all PEMs through the Demand Response Business Practice Manual. Because most demand response resources use day matching,^[1] the Straw Proposal appropriately applies the reform to all PEMs. Limiting the reform to MGO would have minimal practical impact and would not achieve the stated objective.

[1] California Independent System Operator, Demand and Distributed Energy Market Integration Working Group Straw Proposal and Issue Paper, page 11 (March 11, 2026), available at: https://stakeholdercenter.caiso.com/InitiativeDocuments/Straw-Proposal-and-Issue-Paper-Demand-and-Distributed-Energy-Market-Integration-Mar-13-2026.pdf

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

CLECA does not have specific concerns with the proposed approach. CAISO receives and settles aggregated meter data at the resource level, and no ISO business function requires customer-level specification. Demand response providers (DRPs) should retain flexibility in managing this calculation.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

CLECA supports this requirement. Requiring an approved distribution export interconnection, such as a Rule 21 export agreement, before exports are counted is a reasonable safeguard. 

6. Please submit your organization’s overall comments on Track 2.

As stated in CLECA's response to Question 1, CLECA's principal concern with the current Track 2 scope is the exclusion of RDRR reforms that were prioritized in the 2024 Catalog process, and which CLECA has consistently identified as priorities throughout the DDEMI process, most importantly, the expansion of the RDRR MOT. CLECA urges CAISO to reconsider the MOT to the RTPD horizon and include it in the Draft Final Proposal. 

On the Track 2 topics that are within scope, CLECA focuses its comments on three areas of direct relevance to large industrial and commercial customers: the treatment of RDRR for WEIM/EDAM purposes (Question 9), large load participation pathways (Question 10), and the RDRR discrete dispatch limit (Question 11).

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

No comment.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

No comment. 

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

CLECA does not support modifying the existing RDRR construct to accommodate WEIM/EDAM balancing authority area considerations. The current RDRR was carefully constructed through a negotiated settlement process to meet California-specific reliability needs within the California-specific RA construct. Its design elements, including bidding requirements at 95 to 100 percent of the real-time bid cap, reflect California-specific regulatory, operational, and program structures. These features were developed with input from California stakeholders and approved by the CPUC.

Modifying RDRR to serve a broader regional purpose introduces unnecessary risk and complexity that changes made to accommodate other BAAs could alter how the product functions for California participants. CAISO itself acknowledges in the Issue Paper that the RDRR's current approach "may not align with how other BAAs want to bid and make available their reliability DR program."^[1] That misalignment is a reason to build something new that works for all BAAs, not to reshape a product that was specifically designed for California participants.

[1] California Independent System Operator, Demand and Distributed Energy Market Integration Working Group Straw Proposal and Issue Paper, page 13 (March 11, 2026), available at: https://stakeholdercenter.caiso.com/InitiativeDocuments/Straw-Proposal-and-Issue-Paper-Demand-and-Distributed-Energy-Market-Integration-Mar-13-2026.pdf

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

CLECA finds the decision tree framework to be a useful starting point but identifies several areas where it does not fully reflect how large industrial and commercial customers approach demand flexibility. 

• First, the threshold question of whether a large load is "revenue-seeking" may be overly prescriptive and fail to capture how most CLECA members participate. For many large industrial customers, demand flexibility is motivated by cost management, bill stability, and reliability contribution, not just wholesale market revenue alone. The framework should not funnel these customers into supply-side models only when their primary objective is cost avoidance or voluntary curtailment during system stress events. 

• Second, large industrial loads have operational constraints that differ from aggregated residential or commercial demand response. Minimum run times, process safety requirements, ramp limitations, and restart costs are inherent to industrial operations. The participation pathways should accommodate these characteristics rather than requiring large customers to fit into models designed for distributed energy resource aggregations. 

• Third, administrative complexity remains a significant barrier. Metering and registration requirements should be proportionate to the flexibility being offered. Where a large customer is willing to curtail voluntarily during reliability events, the requirements to do so should not exceed the value of participating.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

CLECA supports modifying the exception criteria for the 100 MW RDRR discrete dispatch limit. The proposed change from "and" to "or" in the exception criteria is a practical improvement. The Issue Paper correctly identifies that many aggregated portfolios, including those operated by California’s IOUs, cannot be meaningfully subdivided into sub-resources below 100 MW without creating artificial fragmentation and administrative overhead that does not reflect how these programs are designed or deployed. 

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

CLECA reiterates the central concern raised throughout these comments: none of the RDRR reforms that CLECA identified as priorities during the DDEMI Working Group process have been included in the near-term or mid-term scope of this initiative. 

Of these, MOT reform remains CLECA's most urgent concern. CLECA's comments in the Working Group Session 10 proposed a concrete, near-term compromise: expanding the allowable MOT to align with the RTPD horizon of seven intervals. CAISO's own staff assessed this pathway as relatively straightforward to implement and confirmed it would not require modifications to STUC. CAISO failed to substantively explain why this incremental step cannot be included in the current scope. 

Continued deferral of these issues irreconcilable with DDEMI’s stated objective of enhancing demand flexibility. CLECA has invested significant time in the 2024 Catalog and this stakeholder process and did so in good faith that stakeholder input would meaningfully inform CAISO's policy. Including MOT reform in the current scope would demonstrate that the stakeholder process produces meaningful results and would strengthen the case for continued engagement by stakeholders, including large load customers.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Energy Division staff (ED staff or staff) of the California Public Utilities Commission (CPUC) develop and administer energy policy and programs to serve the public interest, advise CPUC decision makers, and ensure compliance with CPUC decisions and statutory mandates. ED staff provide objective and expert analyses that promote reliable, safe, and environmentally sound energy services at just and reasonable rates for the people of California. 

ED staff appreciate CAISO’s proposed prioritization of problem statements from the working group process to take up in 2026, and its framing of specific proposals for consideration. The opportunity to hear clarifying questions and answers in the discussion was particularly helpful in informing staff comments below.

2. Please submit your organization’s overall comments on Track 1.

ED staff have no objection to the Track 1 proposal to remove restrictions on metering exports at the retail customer level for customers already approved for export on the distribution system, in the general manner proposed. ED staff appreciate CAISO’s diligence in not allowing DER aggregations to include Net Energy Metering (NEM) or Net Billing Tariff (NBT) resources to avoid double compensation of exports, and underscore the need for similar due diligence to be exercised in the Track 1 export proposal. CAISO should continue to ensure customer exports are not being dually compensated through this proposal and other available export compensation mechanisms.

Close collaboration will be needed between CPUC and CAISO on the implementation of this change, and its implications for current Resource Adequacy and Demand Response rulemakings. Some flexibility on implementation timelines may be needed to allow necessary modifications to happen in CPUC jurisdictional rulemaking, tariffs, and programs.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

ED staff supports the extension to whichever PEMs can responsibly include exporting DR resources and reiterates the importance of measures to avoid double compensation that may result from exporting DR resources on retail tariffs that compensate exports. Staff asks CAISO to consider this when examining the operational impacts of the relevant PEMs potentially allowing export at individual resource IDs. We note that this position is consistent with CAISO’s statement in the DDEMI Scoping section, which states that it will not change its tariff to allow Distributed Energy Resource (DER) aggregations to include NEM or NBT resources. ED staff also notes CAISO and CPUC may need to consider whether the proposal introduces risks of unmodeled load shift, which could result in unexpectedly high demand during hours adjacent to DR events, and whether mitigations are possible for any of the PEMs.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

ED staff note that, absent CAISO determining a set approach to distributing value across exporting customers within an aggregation, Investor-Owned Utilities (IOUs) and third-party Demand Response Providers (DRPs) may have different levels of flexibility and fiduciary requirements to ensure equitable treatment of exporting resources.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

ED staff note that, to maintain the safety and reliability of the distribution grid, export capacity under this proposal must not exceed the customer’s existing maximum export level as specified in the approved interconnection agreement. ED staff also note that Rule 21 exporting interconnections should be allowable for exports under this proposal, subject to the Applicability section of Rule 21 and in recognition that for aggregated Rule 21 customers under this proposal, the interconnection would not fall under FERC jurisdiction.

6. Please submit your organization’s overall comments on Track 2.

ED staff will provide comments on Track 2 issues as they are further developed in the future and note the need for close collaboration between CPUC and CAISO on the development of issues in Track 2.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

ED staff invite close collaboration between CPUC, CAISO, and large load customers on the development of large load participation pathways to ensure consistency in planning and operations, both at the regulatory and market design level, to ensure reliability, efficiency, and equity for all California customers.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

ED staff request further analysis by CAISO to ensure that increasing the 100 MW RDRR cap does not have inadvertent negative impacts on the market's ability to optimally and efficiently dispatch RDRR resources.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

2. Please submit your organization’s overall comments on Track 1.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

6. Please submit your organization’s overall comments on Track 2.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

CPower appreciates and supports California ISO's Straw Proposal to allow net exports, as expressed throughout these comments. However, CPower urges the CAISO to recognize the robust stakeholder support for immediately reforming Performance Evaluation Methodologies (PEMs). As noted on page six of the Straw Proposal, a majority of stakeholders requested to prioritize this issue in the near-term. To that end, CPower respectfully requests that the CAISO develop a roadmap and straw proposal for that work in 2026.

The working group's previous discussion on PEMs that are more appropriate for frequently dispatched resources offers a starting point to begin to develop reforms, including prescriptive baselines and device-level or submetering. Most DR baselines have been designed around infrequently dispatched “emergency” type programs. Flexible customers may be willing to be dispatched more frequently, but existing day-matching baselines would be eroded, resulting in understimation of actual load reductions. Customers would be paid less for demand response after installing (and deploying) a behind the meter battery, for instance. The customer could also be penalized for not meeting supply plan enrollment obligations after the baseline is eroded. This creates a huge disincentive for participation in demand response programs. Other jurisdictions are working to address this issue. For example, New York is implementing an Economic Customer Baseline Load in which performance during any event is added back in to the customer baseline. CAISO should prioritize PEM reform to consider solutions to support more frequent dispatch of flexible loads.

2. Please submit your organization’s overall comments on Track 1.

CPower values the opportunity to provide comments on California ISO’s Track 1 Straw Proposal regarding End-User Exports in Demand Response Measurement. As a provider of market-integrated demand response, we strongly support the ISO’s proposal to modernize performance measurement by recognizing customer exports within demand response aggregations.

The current requirement to "zero out" individual customer loads during periods of export prevents the market from capturing the full capability of behind-the-meter storage and generation. By removing this individual-level floor, the ISO will reflect the physical reality of grid-supportive behavior from distributed energy resources in performance evaluations.

CPower supports the ISO’s approach of replacing the individual-level export prohibition with limitations at the aggregate resource level. We agree that maintaining demand response as a load curtailment function at the resource level ensures that curtailment behavior avoids creating unmodeled congestion or distribution system reliability concerns. This is a practical compromise that enables more accurate recognition of customer behavior while maintaining necessary grid safeguards.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

CPower specifically supports applying these changes across all Performance Evaluation Methodologies, including day matching and weather matching, rather than limiting the reform to the Metering Generator Output (MGO) method. Since most proxy demand resources currently utilize day matching, broad application is necessary to ensure the policy has a meaningful impact on market participation. Additionally, not all DER customers have metering that meets the MGO metering requirements. 

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

The potential modification of individual customer exports should be left to aggregator/scheduling coordinator discretion to determine the appropriate methodology. This provides aggregators flexibility in meeting customer operational needs and generally encourages composition of resources such that additional modification of export values is unnecessary.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Approved Rule 21 or WDAT interconnection for export onto the distribution system is necessary to ensure safety and reliability.

6. Please submit your organization’s overall comments on Track 2.

 No comment.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

The current sub-LAP requirement, while effective for California’s nodal market, may pose administrative barriers for WEIM and EDAM entities. We encourage the ISO to prioritize Option 3: Custom Load Aggregation Points. This approach maintains necessary locational granularity for accurate market clearing and congestion management while allowing BAAs to define aggregations that reflect their specific operational needs and network topology.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

No comment.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

No comment.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

No comment.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

We support modifying the 100 MW discrete dispatch limit and its exception criteria. Modern DR programs often consist of thousands of aggregated customers that cannot be easily segmented without causing operational inefficiencies. Updating these criteria to allow larger aggregations will improve the accuracy of resource representation and simplify market participation for large-scale portfolios. It is important to note that the inclusion of any large loads in an aggregation would also generally be subject to any requirements developed in the on-going large loads initiative and stakeholder process.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

CPower, an NRG company, is a leading distributed energy resources monetization and virtual power plant provider, working to enable a flexible, clean and dependable energy future. With over 7.0 GW of capacity at approximately 29,000 sites across the U.S., we unlock the full value of distributed energy resources to strengthen the grid when and where reliable, dispatchable resources are needed most.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Enchanted Rock supports CAISO’s incremental, reliability-first approach that pairs near-term, implementable reforms in Phase 1 with longer-term exploration of broader participation frameworks in Phase 2.

2. Please submit your organization’s overall comments on Track 1.

Behind-the-meter exports can physically occur today where behind-the-meter generation exceeds on-site load. In Enchanted Rock’s experience, customers who deploy on-site generation solutions for resiliency typically deploy significant excess generation to achieve required power availability targets through redundancy. Under current Demand Response System Quality Meter Data (“DR SQMD”) development processes, retail customer load meter data is zeroed out on a customer-by-customer basis, including for customers approved to export[1]. During dispatch intervals, when behind-the-meter generation exceeds on-site load, net exports can and do occur, as reflected by negative net-load meter values[2].

Enchanted Rock supports CAISO’s proposal to remove customer-level export zeroing for customers approved to export, while retaining reliability safeguards through an aggregation-level export limit. An aggregation-level export “floor” (i.e., an aggregation-level limit preventing net exports beyond zero) at the demand response resource or sub-LAP level is an appropriate near-term safeguard to preserve the load-curtailment function and maintain topology alignment[3]. These aggregation-level limits should be clearly framed as transitional measures rather than an end-state for dispatchable, export-capable co-located generation. These Track 1 reforms provide a near-term pathway for recognizing authorized export capability within existing demand response participation models, while preserving the load-curtailment function and associated reliability safeguards.

Enchanted Rock supports applying the export recognition framework across all Performance Evaluation Mechanisms to ensure that authorized behind-the-meter exports can be measured, verified, and considered for their potential contribution to Resource Adequacy and related reliability constructs, rather than limiting these reforms to a single program type. A technology-neutral application will promote consistency, fairness, and efficient participation across the demand response portfolio.

[1] DDEMI Stakeholder Presentation, at 17

[2] DDEMI Stakeholder Presentation, at 17

[3] California Independent System Operator, Demand & Distributed Energy Market Integration: Straw Proposal & Issue Paper 22 (Mar. 13, 2026).

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

Enchanted Rock supports applying the export recognition framework across all Performance Evaluation Mechanisms to ensure that authorized behind-the-meter exports can be measured, verified, and considered for their potential contribution to Resource Adequacy and related reliability constructs, rather than limiting these reforms to a single program type. A technology-neutral application will promote consistency, fairness, and efficient participation across the demand response portfolio.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

Under current Demand Response System Quality Meter Data (“DR SQMD”) development processes, retail customer load meter data is zeroed out on a customer-by-customer basis, including for customers approved to export[1]. During dispatch intervals, when behind-the-meter generation exceeds on-site load, net exports can and do occur, as reflected by negative net-load meter values[2].

Enchanted Rock supports CAISO’s proposal to remove customer-level export zeroing for customers approved to export, while retaining reliability safeguards through an aggregation-level export limit. An aggregation-level export “floor” (i.e., an aggregation-level limit preventing net exports beyond zero) at the demand response resource or sub-LAP level is an appropriate near-term safeguard to preserve the load-curtailment function and maintain topology alignment[3]. These aggregation-level limits should be clearly framed as transitional measures rather than an end-state for dispatchable, export-capable co-located generation. These Track 1 reforms provide a near-term pathway for recognizing authorized export capability within existing demand response participation models, while preserving the load-curtailment function and associated reliability safeguards.

[1] DDEMI Stakeholder Presentation, at 17

[2] DDEMI Stakeholder Presentation, at 17

[3] California Independent System Operator, Demand & Distributed Energy Market Integration: Straw Proposal & Issue Paper 22 (Mar. 13, 2026).

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Behind-the-meter exports can physically occur today where behind-the-meter generation exceeds on-site load. In Enchanted Rock’s experience, customers who deploy on-site generation solutions for resiliency typically deploy significant excess generation to achieve required power availability targets through redundancy. Under current Demand Response System Quality Meter Data (“DR SQMD”) development processes, retail customer load meter data is zeroed out on a customer-by-customer basis, including for customers approved to export[1]. During dispatch intervals, when behind-the-meter generation exceeds on-site load, net exports can and do occur, as reflected by negative net-load meter values[2].

[1] DDEMI Stakeholder Presentation, at 17

[2] DDEMI Stakeholder Presentation, at 17

6. Please submit your organization’s overall comments on Track 2.

CAISO has identified significant large-load growth driven by new industrial facilities, data centers, and residential/fleet electrification, and has appropriately sought pathways for measurable, dispatchable, and reliable response. Many of these emerging loads require very high service reliability and rely on purpose-built, dispatchable co-located generation operated as part of normal reliability and grid-support strategies. These resources are distinct from emergency standby resources limited to infrequent outage response, or on other dispatchable distributed resources capable of responding to identified reliability needs.

Technology-neutral market design should evaluate participation eligibility based on dispatchability, controllability, telemetry, and verifiable performance attributes. Such an approach should preserve eligibility for dispatchable generation that meets these operational criteria and are capable of supporting state energy and reliability objectives. Track 2 participation frameworks should therefore classify co-located resources and large-load adjacent resources based on measurable operational attributes rather than behind-the-meter configuration alone.

Co-located generation capable of export exhibits operational supply characteristics. These resources are dispatchable, controllable, interval-metered, and capable of injecting energy into the grid. Existing demand response constructs, even with Track 1 improvements, remain conceptually focused on load curtailment rather than generation or export. Export-capable, dispatchable resources risk being undervalued or misclassified if constrained to load-limited demand-response-only models. CAISO should evaluate whether existing tariffed participation models can accommodate co-located, export-capable generation with these operational characteristics and, if not, consider developing an appropriate participation pathway—subject to applicable telemetry, settlement-quality measurement, and market-power mitigation requirements—that can credit verifiable net-load reduction and authorized exports.

These comments do not propose that CAISO adjudicate emissions attributes, but rather that participation eligibility remains focused on operational capability, verifiability, and reliability contribution, consistent with the ISO’s statutory role.

The Reliability Demand Response Resource (“RDRR”) is a supply-side demand response product that may clear in the day-ahead market but is dispatched in real time only for reliability purposes, including exceptional dispatch under CAISO Operating Procedure 4420[1]. CAISO is considering enhancements to RDRR or the development of a new reliability-triggered product that explicitly includes behind-the-meter generation commingled with load and/or load reductions, with energy payments only when dispatched and non-performance charges.

Enchanted Rock supports these concepts and encourages incorporation of operating characteristics such as minimum on time and fixed dispatch cost to improve dispatch optimization accuracy and better reflect real resource behavior[2]. The objective should be accurate representation and eligibility, not preferential treatment or guaranteed dispatch. Formal market participation improves CAISO visibility, accountability, and performance certainty during system stress events and can reduce reliance on higher-emission emergency resources.

As large loads, flexible demand, and distributed energy resources continue to reshape power flows and operational conditions, CAISO has identified the need for improved visibility and coordination with co-located and large-load adjacent resources. While these resources may operate behind the meter or self-dispatch under normal conditions, greater transparency into their operational status and capabilities can support more effective real-time system operations and reliability management.

Market participation frameworks can advance these objectives by enabling observable, operationally consistent interfaces between CAISO and dispatchable demand-side and co-located resources. CAISO has emphasized the importance of situational awareness at the transmission-distribution interface and is developing coordination approaches intended to improve real-time and day-ahead visibility into large loads and distributed energy resources, with and without co-located generation. Participation pathways that rely on settlement-quality data, appropriate telemetry, and defined operational coordination protocols can support these goals while respecting the operational role of retail utilities and customers.

Experience in other jurisdictions demonstrates that enhanced visibility and coordination A can be achieved without requiring full grid-facing generator participation. For example, distributed energy resources in ERCOT are registered and provide telemetry to the market operator, even when self-dispatching, which improves transparency and enables system operators to understand available capabilities during system stress events. Similar approaches could be applied where CAISO seeks greater visibility or dispatch optionality provided that market structures offer clear incentives for resources to participate.

Participation frameworks for co-located and export capable resources should therefore emphasize verifiability and transparency through observable, settlement-quality measurement, defined telemetry standards, and clear eligibility and approval requirements[3]. Importantly, if CAISO seeks additional visibility coordination or control over these resources, corresponding market incentives should be available to support necessary investments. Such an approach can enhance operational coordination and reliability outcomes while maintaining market integrity and voluntary participation.

[1] DDEMI Straw Proposal, at 19 (Mar. 13, 2026).

[2] California Independent System Operator, D-DEMI Working Group Proposals: Reliability Demand Response Resource 5, 8 (July 2025).

[3] California Independent System Operator, Demand & Distributed Energy Market Integration Discussion Paper 26 (Nov. 26, 2025).

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

An aggregation-level export “floor” (i.e., an aggregation-level limit preventing net exports beyond zero) at the demand response resource or sub-LAP level is an appropriate near-term safeguard to preserve the load-curtailment function and maintain topology alignment[1]. 

[1] California Independent System Operator, Demand & Distributed Energy Market Integration: Straw Proposal & Issue Paper 22 (Mar. 13, 2026).

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

Participation pathways that rely on settlement-quality data, appropriate telemetry, and defined operational coordination protocols can support these goals while respecting the operational role of retail utilities and customers.

Experience in other jurisdictions demonstrates that enhanced visibility and coordination A can be achieved without requiring full grid-facing generator participation. For example, distributed energy resources in ERCOT are registered and provide telemetry to the market operator, even when self-dispatching, which improves transparency and enables system operators to understand available capabilities during system stress events. Similar approaches could be applied where CAISO seeks greater visibility or dispatch optionality provided that market structures offer clear incentives for resources to participate.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

The Reliability Demand Response Resource (“RDRR”) is a supply-side demand response product that may clear in the day-ahead market but is dispatched in real time only for reliability purposes, including exceptional dispatch under CAISO Operating Procedure 4420[1]. CAISO is considering enhancements to RDRR or the development of a new reliability-triggered product that explicitly includes behind-the-meter generation commingled with load and/or load reductions, with energy payments only when dispatched and non-performance charges.

Enchanted Rock supports these concepts and encourages incorporation of operating characteristics such as minimum on time and fixed dispatch cost to improve dispatch optimization accuracy and better reflect real resource behavior[2]. The objective should be accurate representation and eligibility, not preferential treatment or guaranteed dispatch. Formal market participation improves CAISO visibility, accountability, and performance certainty during system stress events and can reduce reliance on higher-emission emergency resources.

[1] DDEMI Straw Proposal, at 19 (Mar. 13, 2026).

[2] California Independent System Operator, D-DEMI Working Group Proposals: Reliability Demand Response Resource 5, 8 (July 2025).

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

CAISO has identified significant large-load growth driven by new industrial facilities, data centers, and residential/fleet electrification, and has appropriately sought pathways for measurable, dispatchable, and reliable response. Many of these emerging loads require very high service reliability and rely on purpose-built, dispatchable co-located generation operated as part of normal reliability and grid-support strategies. These resources are distinct from emergency standby resources limited to infrequent outage response, or on other dispatchable distributed resources capable of responding to identified reliability needs.

Technology-neutral market design should evaluate participation eligibility based on dispatchability, controllability, telemetry, and verifiable performance attributes. Such an approach should preserve eligibility for dispatchable generation that meets these operational criteria and are capable of supporting state energy and reliability objectives. Track 2 participation frameworks should therefore classify co-located resources and large-load adjacent resources based on measurable operational attributes rather than behind-the-meter configuration alone.

Participation frameworks for co-located and export capable resources should therefore emphasize verifiability and transparency through observable, settlement-quality measurement, defined telemetry standards, and clear eligibility and approval requirements[1]. Importantly, if CAISO seeks additional visibility coordination or control over these resources, corresponding market incentives should be available to support necessary investments. Such an approach can enhance operational coordination and reliability outcomes while maintaining market integrity and voluntary participation.

[1] California Independent System Operator, Demand & Distributed Energy Market Integration Discussion Paper 26 (Nov. 26, 2025).

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

Enchanted Rock respectfully recommends that CAISO:

• Implement Track 1 export recognition reforms;
• Treat aggregation export limits as transitional measures rather than permanent constraints;
• Advance evaluation of participation pathways for co-located, export-capable generation through Track 2, building on near-term export recognition under Track 1 and assessing whether tariffed models can accommodate supply-like operational characteristics or whether targeted tariff changes are warranted;
• Enhance the RDRR construct or develop reliability-triggered products that accommodate co-located generation and accurately reflect operating characteristics; and,
• Preserve technology-neutral eligibility that does not categorically exclude dispatchable resources with ultra-low or offset emissions profiles, provided they meet CAISO’s operational, telemetry, and performance requirements.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Leap appreciated the discussion and opportunity to provide comments at the DDEMI March 13 meeting, and it echoes many of these comments in its answer to the questions below. Leap does not have feedback to provide in response to all of CAISO’s questions at this time, but it reserves the right to do so in the future.   

2. Please submit your organization’s overall comments on Track 1.

Leap commends CAISO on developing a Track 1 Straw Proposal that is responsive to one of the primary problem statements put forward by stakeholders over the course of the working group, and for recognizing the importance and feasibility of moving quickly towards a solution. CAISO’s proposed approach to crediting grid exports towards DR resource performance will expand the amount of capacity that DR providers (DRPs) are able to offer the market, and the CAISO’s characterization of this as an “accounting rule” change correctly identifies the relative simplicity with which it can be implemented. Leap encourages CAISO staff to move forward with this proposed change for approval at CAISO’s August Board meeting, which should provide DRPs with ample time to incorporate this change into their Load Impact Protocol (LIP) submissions in 2027. 

CAISO should also consider exploring alternative approaches to implementing this proposal that could expand the amount of capacity that it could add while still avoiding any unmodeled congestion on the grid. For example, while putting in place a new “floor” prohibiting exports at the Resource level is straightforward to implement from an accounting standpoint, it may create operational complexity for aggregation management, as DRPs will often group similar device types (e.g. exporting batteries) into the same Resource to ensure the Resource’s dispatch preferences are shared by all devices in the Resource. However, as described in the straw proposal, a Resource made up primarily of exporting batteries would still see a significant amount of its capacity “zeroed out” under this approach. 

If CAISO instead instituted the cap at the DRP level rather than the Resource level, then the DRP could continue incorporating similar device types into the same resource while ensuring that their full capacity value can be offered to the market. In this case, CAISO would assess the DR performance for a DRP’s full portfolio of Resources on a single Sub-LAP, and zero out any net exports that exist across this full Sub-LAP-level portfolio. This would allow individual Resources within a DRP’s Sub-LAP-level portfolio export back to the distribution grid, while ensuring that this broader portfolio is only providing a distribution-level load reduction in a way that corresponds to market topology.

However, while the above approach has merit, it should not be pursued as an alternative to CAISO’s existing straw proposal if doing so would cause implementation of that straw proposal to be delayed. To the extent this alternative would take additional time to refine and develop, Leap recommends moving forward with the existing proposal this year and deferring consideration of ways to expand on this proposal to the mid-term discussion of enhancements to Performance Evaluation Methodologies (PEMs) outlined in the DDEMI Scoping section at the end of the discussion paper.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

The straw proposal should apply to all PEMs. CAISO accurately identified that the vast majority of DR Resources – including those made up of export-capable battery resources – do not use the MGO baseline, so limiting this proposal to MGO only would largely eliminate the benefits it could provide. Specifically, there are several reasons why expanding the straw proposal to non-MGO baselines is appropriate.

1. Many batteries – particularly those in the residential space – are unable to meet the strict metering accuracy requirements required to use interval data in the MGO baseline. As CAISO’s straw proposal does not contemplate changing those accuracy requirements, this proposal should apply to day-matching and other baselines that use utility meter data rather than asset-level interval data, as many customers with export-capable devices will likely still continue to use utility meter-level baselines.

2. This baseline would be a good fit for a number of DR customers that don’t have batteries and would therefore be ineligible for the MGO baseline. Specifically, customers with rooftop solar and smart thermostats often face a situation where load reductions from their smart thermostats aren’t fully captured by existing day matching baselines because their solar output makes their net load negative for a large portion of the DR event period. Allowing individual site exports to be credited towards DR performance would allow these customers to be compensated for the incremental load reduction these customers’ smart thermostats can provide, which will be particularly valuable on hot days when reducing site-level load would allow additional solar exports from that site to support system-wide reliability. 

3. Customers using the EVSE baseline may be able to take advantage of this change in a future where electric vehicle-to-grid exports are more widely enabled.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

Questions around allocation of DR payments to individual customers can be handled by DR providers as part of their partner-level and customer-level agreements, and it does not need to be addressed by CAISO within this straw proposal.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Leap agrees that exporting customers should have the necessary approvals from their utility distribution company (UDC) to export onto the distribution system, and it agrees with CAISO that this issue can be addressed as part of the UDC’s existing review process of meters enrolled in the DRRS.

6. Please submit your organization’s overall comments on Track 2.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

Leap recognizes that the DRRS system is imperfect, particularly for WEIM/EDAM. However, using BAA-managed registration systems instead, without a CAISO-approved pathway for third parties, could create an exclusionary system that is potentially inconsistent with FERC Order 2222. As an alternative approach, CAISO could explore the development of a regional centralized registration system that is more available to WEIM entities and also streamlines enrollment of resources relative to the DRRS. Although CAISO staff rightly pointed out the weakness of RTO systems with less robust registration checks, there is likely a middle ground to these other “lighter-touch” options and the current DRRS structure. However, to the extent that Track 2 does address this topic, it should not slow down any of the regulatory reforms or tariff changes discussed or proposed in Track 1.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

Leap appreciates CAISO identifying that Tracks 1 and 2 are only the first steps in a multi-year process, and it looks forward to continuing to engage with CAISO across this multi-year initiative. Leap supports the inclusion of additional PEMs enhancements as a mid-term topic in this endeavor, but it disagrees with CAISO’s decision to exclude device-level registration of DR resources from consideration. While complex, this topic could have significant benefits, and it was called out by a number of stakeholders as an important reform over the course of the DDEMI working groups. 

It’s also a topic that may come up in other regulatory proceedings in the near future. In the CPUC’s new rulemaking on Enhancing DR (D.25-09-004), several stakeholders proposed addressing device-level registration and measurement as an effective solution to resolve dual participation conflicts by allowing customers to participate in multiple DR programs with different devices, and “Data Systems and Processes” are currently scoped into this rulemaking for future discussion. Given that CAISO may already be revisiting the structure of DR registration in wholesale markets as part of its efforts to improve participation options for WEIM/EDAM resources, it would be prudent to include device-level registration as a mid-term discussion topic in this initiative, allowing CAISO staff to keep it in scope so that it can coordinate with other regulatory agencies if/when these types of changes are discussed elsewhere. 

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

MCE appreciates the opportunity to submit these comments on the meeting discussion on March 13, 2026 and the “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper. MCE is supportive of the CAISO’s proposed direction of implementing near-term practical solutions, alongside the exploration of longer-term market design enhancements. We encourage the CAISO to maintain this approach as outlined in the paper.

2. Please submit your organization’s overall comments on Track 1.

MCE strongly supports Track 1 as the most immediate near-term solution. MCE commends and supports the CAISO’s goal of bringing the Track 1 proposal to the Board in August 2026. The Track 1 proposal addresses a critical limitation of the current Proxy Demand Resources (PDR) model by shifting the current export prohibition to the aggregation level, rather than the current individual customer level. This will allow demand response providers (DRPs) and the CAISO to capture the additional export capacity that already exists, while maintaining the resource model as a load curtailment product. This is a practicable, near-term solution that will result in immediate benefits to the market and its participants with minimal implementation effort required for the CAISO.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

The change in the Track 1 straw proposal should apply to all Performance Evaluation Methodologies (PEMs). The underlying problem of accounting for customer-level exports exists across all PEMs, therefore the change should apply to all PEMs. MCE agrees with the CAISO’s concern as noted in the March 13, 2026 presentation – limiting the proposal to th emetering generator output (MGO) methodology would significantly constrain the proposal’s impact given that most existing PDR resources use other PEMs.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

MCE strongly agrees with the CAISO’s proposal in which scheduling coordinators (SCs) submit aggregated meter data for settlement, and the CAISO need not specify which end-use customer would be zeroed out. MCE further recommends that the CAISO provide maximum flexibility to the DRPs/SCs regarding the treatment of individual end-use customers within an aggregation, given that DRPs/SCs are best positioned to manage and optimize their unique portfolio-level resources. 

As the DDEMI effort explores longer-term reforms, MCE encourages the CAISO to consider how current aggregation and registration rules can limit the full potential of the Track 1 proposal. Currently, when the composition of an aggregation changes, DRPs must effectively recreate and re-register the aggregation, which significantly limits overall scalability. Future enhancements to PDR should enable more dynamic portfolios and reduce associated administrative burdens, such as by allowing for more flexible or “like-for-like" substitution of end-users within an aggregation. 

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

MCE supports the Track 1 proposal requirement that exporting customers must have an approved interconnection agreement with the governing utility distribution company that enables them to export energy (i.e., Rule 21 export agreement). This appropriately acknowledges the existing interconnection approval processes at the distribution-level, without imposing duplicative requirements at the CAISO level. 

6. Please submit your organization’s overall comments on Track 2.

MCE has no comments on the Track 2 Issue Paper at this time, but intends to remain an active participant in future stakeholder sessions and may offer comments on subsequent iterations of the proposal. 

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

See Question 6 response.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

See Question 6 response.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

See Question 6 response.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

See Question 6 response.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

See Question 6 response.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

MCE has no additional comments on the Track 1 Straw Proposal, and no comments on the Track 2 Issue Paper at this time. MCE intends to remain an active participant in future DDEMI stakeholder sessions, and plans to offer comments on subsequent iterations of the proposals. 

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Nostromo Energy appreciates the CAISO soliciting stakeholder comments on their March 13^th, 2026, Demand and Distributed Energy Market Integration Initiative Straw Proposal discussion. 

The DDEMI discussions began over a year ago to identify and prioritize improvements to the existing DER/DR mechanisms.  This lengthy discussion process identified a number of specific DDEMI priorities and Nostromo believes that bringing these identified priorities into the policy phase align well with Nostromo’s work towards helping to meet the objectives of California Senate Bill 846 (SB 486), bringing 7 GW of “shift” resources into the market by 2030. 

However, Nostromo is concerned about the continued slow pace of this initiative.  Nostromo acknowledges, but is disappointed with, the limited resources available for the DDEMI policy efforts.  These limitations will create significant delays in implementing the identified DDEMI priorities and jeopardize meeting the 2030 SB 486 milestone.

Recent publications by both the California Energy Commission (CEC)[1] and the National Laboratory of the Rockies (NREL)[2] illustrate the effectiveness of thermal energy storage systems in meeting the SB 486 targets.  These papers, along with Nostromo’s own operational observations as presented to the working group on March 3^rd, 2025, highlight the direct value of introducing a more accurate Thermal Performance Evaluation Methodology (PEM) to the market in order to support the effective deployment of such resources to assist California in meeting the SB 486 goals.

Because of this, Nostromo emphasizes that the PEM Enhancement efforts, identified as a Track 2 mid-term priority, should be reprioritized as a short-term policy priority to begin as a focused effort immediately once the initial Track 1 treatment of exports by end-use customers policy process is completed.

[1] https://www.energy.ca.gov/publications/2025/thermal-energy-storage-system-packaged-hvac-systems

[2] https://docs.nrel.gov/docs/fy25osti/93359.pdf

2. Please submit your organization’s overall comments on Track 1.

The Track 1 proposal to remove meter submission limitations to allow for the export of behind the meter energy is a low-impact effort that recognizes current resource constraints within CAISO. yet can still be implemented quickly and effectively.  Nostromo acknowledges, but is disappointed with, the limited resources available for the DDEMI policy efforts.  While these limitations are disappointing Nostromo does believe that the proposed changes to the meter data submission guidelines can be implemented quickly and believes that it should begin immediately, to maximize the market benefits of behind the meter storage, as outlined in Leap Energy’s presentation during the seventh working group discussion.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

Nostromo has no comments on this item.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

Nostromo has no comments on this item.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Nostromo has no comments on this item.

6. Please submit your organization’s overall comments on Track 2.

Nostromo believes that the proposed PEM enhancements discussion should be prioritized ahead of any specific Large Load policy efforts. 

The questions surrounding Large Load resources within the DER/DR space were discussed briefly during the seventh DDEMI Working Group session, but the requirements involved with Large Load integration are still being discussed under their own separate initiative.   We believe that this dedicated Large Load initiative would be the most appropriate platform to better consider how such resources can participate in the DER/DR market process since such participation will be heavily dependent on any technical requirements identified in said discussions.

Nostromo does not object to including potential Large Loads PEM evaluations as a sub-category within the broader PEM enhancement process but do not believe that such an inclusion should delay the introduction of new and/or modified PEMs already discussed during the DDEMI working group sessions, and that any new and/or modified PEMs be ready to for use in the market on or before June 1, 2027.  Nostromo strongly believes that this aggressive timeline is crucial in meeting California’s SB 486 requirements by 2030.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

Nostromo has no comments on this item.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

Nostromo has no comments on this item.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

Nostromo has no comments on this item.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

Nostromo has no comments on this item.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

Nostromo has no comments on this item.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

Nostromo has attached both thee CEC and NREL papers referenced  in section 1 for CAISO’s review.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

PG&E supports CAISO’s Track 1 proposal as a productive step toward unlocking the contributions of behind-the-meter (BTM) resources through recognition of exports. 

PG&E appreciates the opportunity to participate in the DDEMI initiative and thanks CAISO for its continued efforts and progress in advancing demand and distributed energy market integration. PG&E finds the Track 1 straw proposal on exports to be a productive approach that will help address barriers to valuing the contributions of BTM exports, paving the way for recognition of Resource Adequacy (RA) value that will promote affordability for rate-payers. PG&E also appreciates the progress represented by the Track 2 issue paper, recognizing its importance in further enhancing demand flexibility. We look forward to additional stakeholder engagement as these proposals evolve.   

PG&E’s comments can be summarized by the following key points: 

Track 1 

• The straw proposal is an innovative approach to address deliverability concerns with providing RA value for behind-the-meter (BTM) exports. 

• Coordination with the CPUC is necessary to address compensation for both retail and wholesale revenues, enhancements to utility distribution company review process, and the remaining barriers outlined by the CPUC. 

• Matters that can be addressed in parallel with implementation include distribution line losses and RA valuation of exports. 

• New market models that fully value Behind the Meter exports warrant continued exploration. 

Track 2 

• Issues specific to the WEIM/EDAM entities should be resolved in coordination with CAISO.  

• PG&E defers to CAISO and WEIM/EDAM entities to develop locational constructs that best align with the operational and regulatory structures of the individual BAAs 

• A?solution developed by CAISO and WEIM/EDAM BAAs should be applicable to potential control group registry. The existing RDRR product should not be modified. 

• The supply side participation pathway is PG&E’s current approach to large load flexibility. 

• The RDRR discrete dispatch exception criteria should be modified. 

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2. Please submit your organization’s overall comments on Track 1.

The straw proposal is an innovative approach to address deliverability concerns with providing RA value for behind-the-meter (BTM) valuation of exports.   

PG&E appreciates CAISO’s efforts to advance market integration for distributed energy resources through the recognition of customer-level exports and views the DDEMI Track 1 Straw Proposal as a constructive, incremental step toward enhancing DER participation. PG&E commends CAISO for taking the necessary steps to revise the PDR and RDRR market models to reflect exports. However, PG&E recognizes that fully realizing the value of behind-the-meter exports will also require action by the California Public Utilities Commission (CPUC) to address issues within its jurisdiction, including the eight barriers to BTM resources providing RA, initially identified in a 2020 decision1 .The CAISO proposal addresses two identified barriers: 

• Wholesale market participation including metering, dispatch control, and communication with CAISO 

• Deliverability determination 

PG&E identifies several areas where CPUC action is necessary to fully operationalize the Straw Proposal. As discussed in these comments, some issues must be resolved prior to market implementation, while others may be addressed in parallel. This approach would allow certain benefits of the Straw Proposal to be realized while remaining policy and implementation issues continue to be evaluated. 

Accordingly, PG&E supports continued progress under the DDEMI initiative, while emphasizing that the current proposal should be viewed as transitional and not a final solution to the broader policy issues associated with export valuation. As discussed below, PG&E believes new market models are needed to fully value Behind the Meter exports.   

Matters that should be addressed prior to implementation of the Track 1 straw proposal 

Coordination with the CPUC is necessary to address compensation for both retail and wholesale revenues. 

One of the fundamental issues that needs to be addressed before implementation of this proposal, is double compensation between retail Net Energy Metering (NEM)/Net Billing Tariff (NBT) credits and wholesale market energy revenues for the same energy exports from BTM resources.  A methodology needs to be developed that would ensure customers are compensated only once and ratepayers pay only once for the same energy exports.  PG&E understands that this topic needs to be addressed by the CPUC and is out of the scope of CAISO Tariffs, but emphasizes that coordination with the CPUC is essential before implementation of this proposal.  

Enhancements to Utility review process will be necessary to ensure suitability of locations to export. 

Utility Distribution Company (UDC) location review process changes for Service Accounts registered in the DRRS by DRPs may also be necessary to ensure the customer location is permitted to export, such as verification of Rule 21 export status and suitability of local distribution systems to accommodate additional exports.  Rule 24 system upgrades or similar review processes would be required to accomplish the increased screening.  This would require coordination with the CPUC.  Changes to DRRS functionality may also be required on the CAISO side.  For example, the DRRS may need to be enhanced to include a new parameter in the location creation process to allow a DRP to indicate that a particular Service Account is to be reviewed by the UDC for its eligibility to export as part of the resource aggregation.     

Matters that warrant consideration and further study, but can be done after initial implementation of the Track 1 straw proposal 

Export value may need to be adjusted for distribution line losses. 

Distribution line losses occur when energy is transported across the grid.  Failure to account for these impacts could overstate the value of the exported energy. While PG&E doesn’t believe this issue needs to be addressed prior to proposal implementation, it is an issue that should be monitored after implementation of the proposal, with potential settlement methodology changes in future enhancements. 

Recognition of RA values from exports  

One of the largest benefits of recognizing BTM exports is the RA value represented by the additional capacity, which will require action by the CPUC to develop a Qualifying Capacity value for exports and by CAISO to recognize Net Qualifying Capacity, among other matters outlined in the remaining barriers outlined by the CPUC but not addressed by this proposal: 

• Forward determination of capacity associated with renewable production, consumption, charging, and export 

• RA requirements associated with customers providing capacity 

• Cost for energy associated with consumption, charging, and export 

• Load forecasting and adjustment for BTM resources 

• Interaction of such resources with existing BTM resources such as proxy DR 

However, PG&E believes the straw proposal could be implemented in a transitional sequence, recognizing wholesale energy from exporting PDRs in the first phase of implementation, with subsequent recognition of the RA capacity value as fundamental structures are implemented.   

Market participants may include customers in the resource to inflate the baseline. It’s unclear to PG&E if this is an issue. 

PG&E notes that the current proposal creates an incentive to recruit customers in the resource aggregation that provide limited or no load reduction capabilities, primarily to increase or inflate the aggregate baseline load to avoid reaching net exports for the overall aggregation. This could be acceptable, but PG&E wants to better understand any potential unintended consequences, for example, increased market inefficiency and administrative burden, of this design. 

New market models that fully value Behind the Meter exports warrant continued exploration. 

While PG&E supports the straw proposal, PG&E notes that the approach could be cumbersome and encourages the CAISO and stakeholders to further explore export participation frameworks, such as DERA-type models which permit the injection of energy to the CAISO grid, rather than restrict exports in order to maintain the PDR/RDRR as load curtailment models.  Such a framework would likely be a better long-term solution that reflects how these resources operate and avoid distorting market incentives, while fully recognizing the potential contributions of distributed energy resources. 

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

The straw proposal should apply to all PEMs. 

PG&E believes the straw proposal is broadly applicable and should apply to all PEMs. Given the low utilization and implementation challenges associated with the MGO methodology for mass deployment of behind-the-meter (BTM) storage, applying the straw proposal to the Day Matching methodology would likely yield the greatest benefits. 

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4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

Allocation of export credits to individual customers should be determined by the retail DR program rules. 

The Demand Response program should define how exporting customers are treated when included in an aggregation that is otherwise zeroed out to preserve the prohibition on resource-level exports. The customer relationship or retail program could consider either (1) a pro rata allocation approach or (2) compensation for all exports; however, (2) may raise retail program cost-effectiveness considerations when the sum of end-use exports leads to a resource-level export. This issue underscores the need to develop CAISO market models that fully and appropriately compensate behind-the-meter DER exports. 

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Valid interconnection is required for exports.?? 

PG&E agrees that an approved interconnection agreement is essential for exporting customers to help preserve the safety and integrity of the distribution system.  As noted above, an enhanced UDC review process is also necessary to incorporate additional considerations, including distribution system constraints. 

6. Please submit your organization’s overall comments on Track 2.

Issues specific to the WEIM/EDAM entities should be resolved in coordination with CAISO.  

PG&E appreciates the consideration of the issues raised in Track 2 and largely defers to CAISO and the WEIM/EDAM entities on the specific details and implementation of proposed enhancements that apply to the WEIM/EDAM entities but not to the CAISO BAA. PG&E hopes that, as discussions around the Demand Response Registration System (DRRS) alternatives progress, the requirements and insights from the PG&E’s control group baseline proposal can be thoughtfully integrated, in anticipation of a future policy initiative addressing additional Performance Evaluation Methodology enhancements. 

Additionally, PG&E offers comments on the large load participation pathways and RDRR proposals in the sections below. 

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

PG&E defers to CAISO and WEIM/EDAM entities to develop locational constructs that best align with the operational and regulatory structures of the individual BAAs, consistent with the standard principles of market design that CAISO identified at the outset of the DDEMI initiative. 

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

A?solution developed by CAISO and WEIM/EDAM BAAs should be applicable to potential control group registry, per PG&E’s proposal not to create control group locations in DRRS. 

PG&E appreciates CAISO’s consideration of more flexible approaches to demand response registration, particularly where existing DRRS requirements may introduce administrative burden without commensurate market integrity benefits. As CAISO notes, DRRS was designed to support customer-level oversight for active demand response participation within the CAISO BAA, including dual-participation checks and enforcement of retail and wholesale enrollment rules. 

PG&E encourages CAISO to explicitly recognize that these objectives do not apply to customers not enrolled in a Demand Response program when these customers are used solely for statistically matched control group development. Requiring customers not enrolled in a Demand Response program to be registered in DRRS for matched control group baselines introduces legal, operational, and competitive neutrality challenges. Leveraging these customers for matched control groups would improve reliability, prevent double counting, and enhance settlement accuracy. 

As CAISO evaluates alternatives to customer-by-customer registration, particularly portfolio-level and audit-based frameworks, the?design should be applicable to control group registry for customers who are not market participants and do not receive dispatch, awards, or compensation. Doing so would align DRRS use with its intended purpose while enabling more accurate and feasible control group settlement methodologies. 

PG&E supports maintaining robust registration, validation, and audit requirements for participating demand response resources, and believes that clearly separating participation requirements from evaluation constructs will strengthen both market integrity and analytical accuracy. 

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

The existing RDRR product should not be modified. 

PG&E does not believe that the existing RDRR construct should be modified for participation by WEIM/EDAM entities.  Instead, a suitable construct to support the reliability demand response needs specific to the WEIM/EDAM entities should be developed.  CAISO should engage the DDEMI stakeholder community if enhancements to the existing RDRR product or development of a new reliability product applicable to all BAAs are under consideration.  

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

The supply side participation pathway is PG&E’s current approach to large load flexibility. 

The large load participation pathways, particularly the supply side pathway, are consistent with PG&E’s current approach to large load participation. However, PG&E is interested in understanding the perspectives of other stakeholders, especially large load entities or their representatives. We encourage further discussion to explore whether these pathways meet the needs and preferences of all stakeholders and to identify potential improvements. 

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

The discrete dispatch exception criteria should be modified. 

PG&E supports revising the exception criteria for the RDRR discrete dispatch limit of 100 MW, as described in the Track 2 Issue Paper. Given the trend toward larger aggregations and the increasing potential for large loads to participate as discrete resources, PG&E agrees that it is not practical to disaggregate customers into sub-resources to remain below the 100 MW threshold. PG&E also recognizes that some individual locations may exceed 100 MW, creating the potential for very large resources to participate in RDRR. 

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

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1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

San Diego Gas and Electric (SDG&E) provides these comments on the Track 1 Straw Proposal which focuses on treatment of exports by end-use customers that are part of a demand response resource in ISO markets and metering enhancements related to this treatment.  SDG&E also provides comments on the Track 2 issue paper wherein CAISO (1) assesses additional demand flexibility enhancements to support demand response and large load participation across the Western Energy Imbalance Market (WEIM) and the Extended Day-Ahead Market (EDAM) footprints, (2) examines participation pathways for large loads. As new large-scale electricity consumers expand across the region, some loads may be capable of providing operational flexibility similar to traditional demand response resources, and (3) explores potential refinements to RDRR to better reflect operational capability

2. Please submit your organization’s overall comments on Track 1.

See comments below.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

SDG&E recommends limiting the change in the straw proposal to the Metering Generator Output methodology only. Creating a pathway for customers with interconnection agreements who are not otherwise compensated under retail rates (e.g., NEM, NBT, V2G-compensated programs) to participate in DR may be a way to increase the share of behind-the-meter resources that participate in the market. Customers on existing NEM/NBT tariffs should be excluded to avoid doubly compensating them for a single export. Additionally, changing all Performance Evaluation Methodologies imposes these new operational costs on DR programs across the board. SDG&E encourages the CAISO to account for any incremental operational costs for DR Programs when considering these changes.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

There are other operational considerations that the Straw Proposal does not fully address, and which should be tested and considered before implementing changes to the settlement process overall. For example: If the straw proposal is extended to non-MGO methodologies, further detail about how to handle aggregate net exports during the baseline period is needed. The straw proposal does not clearly address how to handle the baseline adjustment window for the 10-in-10, 5-in-10, and weather matching methodologies when a resource has aggregate net exports. A resource that has aggregate net exports for any baseline hours may result in an undefined ratio between energy use on event and non-event days.

Another item that should be considered is that the straw proposal creates an incentive for demand response providers (DRP) to expand net-exporting resources by enrolling new individual customers regardless of their behavior during demand response events. Their inclusion in the aggregate resource would raise the resource’s baseline above the energy exported by responsive customers. Adjusting the resource’s baseline in this way would allow them to capture more value without providing additional incremental benefits. For example, a demand response provider could add customers with non-exporting resources to an aggregate resource alongside customers with exporting resources in order to ensure that the overall resource is not exporting energy during the event or on the baseline days. Alternatively, a DRP might include only customers with batteries in a resource, but dispatch only a portion of the batteries to ensure that the overall resource is not exporting. These strategies distort the size of the calculated load impact without changing the programs’ contribution to grid stability. It is not clear to SDG&E that there is a benefit to the grid from combining customers in this manner therefore creating an incentive for DRPs to do so may result in unintended consequences.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

At this time, SDG&E concurs that eligible exporting Rule 21 interconnection customers should have an approved interconnection (for SDG&E, an executed exporting Rule 21 interconnection agreement) to be allowed to participate in the program.  However, having only an executed interconnection agreement is not sufficient to determine whether there will be incremental expenses from participation in this program, some of which may be material.

To complete an interconnection agreement, a single interconnection customer with a Rule 21 export interconnection request will have been appropriately studied for the impact of the generating facility on the distribution system and transmission system (if any).  It will likely have the appropriate metering and telemetry (if over 1 MW in size) installed so that its output can be appropriately monitored by SDG&E grid operations personnel and also to render correct billings.  This paragraph applies to non-NEM/NBT generating facilities as well as any NEM/NBT interconnection requests greater than 30 kW which also are evaluated by SDG&E engineers for exporting impact to the distribution and/or transmission system.  However, at this time SDG&E is doubtful that  existing NEM/NBT interconnection requests greater than 30 kW have the necessary metering and telemetry equipment installed to allow for monitoring and billing for this program change to succeed.  This could lead to additional costs to the interconnection customer to install this metering and telemetry and other related equipment required to participate in this program.

The previous paragraph discusses a single generating facility.  SDG&E understands for this program to be successful it will seek to aggregate a large number of such facilities Additionally, it is unclear if these aggregations could participate in the market only through their LSE as the scheduling coordinator, or if an aggregator who is not the LSE for these customers would be managing the aggregation and baseline calculation of these resources. SDG&E would appreciate clarification on how these resources could participate in the market, and any disconnect in load calculations that may occur if the SC was an entity other than the LSE.

Finally, for any/all non-exporting Rule 21 (largely behind the meter resources) which have never been evaluated by SDG&E as exporting resources, for such projects to participate in this program at all, they would have to undergo new studies or at least newly developed screening to determine if there would be incremental issues related to turning a non-export facility into an exporting generating facility.  For certain, none of the non-exporting Rule 21 existing fleet would have the appropriate metering and telemetry equipment required for operations and billing purposes.  Thus SDG&E does not believe the non-export Rule 21 interconnection requests should be eligible to participate in this program without dramatic changes to Rule 21 interconnection study process, and/ or expensive restudies using the existing Rule 21 interconnection study process.

6. Please submit your organization’s overall comments on Track 2.

See comments below.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

No comment.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

Without specific detail, it is difficult to ascertain all possible implications.  For example, the CAISO today maintains the DRRS system, with those customers who are registered to participate in CAISO markets.  The CAISO notifies SDG&E when a customer has changed registrations or is participating within a different resource (switching which entity it is participating under the CAISO market). This has implications within the dual participation rules of the CPUC, for example. The DRRS would have to differentiate resources that could participate outside the BAA, and there would have to be rules about timely notifications, and prioritizing registrations possibly.  

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

SDG&E does not object to the ISO pursuing the exploration of such modifications, but is unclear how such modifications would work.  For example, DR programs under the CPUC’s jurisdiction would have to adhere to the state’s rules on DR (such as dual participation), and resources outside would not – it is not clear to SDG&E that these nuances have been fully considered and recommends further development/exploration before moving forward. 

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

No comment.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

No comment.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

No comment.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

SEIA appreciates the CAISO’s continued engagement through the Demand and Distributed Energy Market Integration (DDEMI) initiative and supports the ISO’s approach of pairing near-term, implementable reforms with longer-term market design exploration. SEIA views this initiative as a critical step toward aligning wholesale market rules with the physical and commercial realities of modern distributed resources. In particular, the Track 1 Straw Proposal represents a targeted and overdue correction to demand response performance measurement that will materially improve the ability of BTM resources to contribute reliable flexibility to CAISO markets.

2. Please submit your organization’s overall comments on Track 1.

SEIA supports the Track 1 proposal to allow customer-level exports from BTM resources to be reflected in demand response performance measurement. Current rules that require Scheduling Coordinators to zero out negative meter data at the individual customer level artificially cap the performance of demand response resources that include BTM batteries, even when those batteries are physically exporting energy to the distribution system during dispatch intervals and are authorized to do so under retail interconnection agreements. This accounting treatment understates the actual grid benefit provided by BTM storage and prevents CAISO from fully leveraging resources that are already deployed, interconnected, and capable of responding to system needs. The proposed reform shifts the export “floor” from the individual customer to the aggregated resource. This is an appropriate improvement over the current state. SEIA encourages the CAISO and stakeholders to continue evaluating whether the “floor” must stop there.

By allowing customer-level exports to be reflected in Demand Response Energy Measurement (DREM), the Track 1 proposal directly increases the usable and compensable capacity of BTM batteries participating in PDRs and RDRRs. This change improves settlement outcomes, enhances event performance, and better aligns wholesale incentives with retail-level investment decisions.  The proposal does not alter existing retail export rules. It simply ensures that wholesale performance measurement recognizes energy that is already flowing to the gird during dispatch intervals.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

SEIA supports CAISO’s intent for the Track 1 reform to apply across all Performance Evaluation Methodologies (PEM). Most existing PDRs rely on day matching PEM and limiting this reform to a narrow subset of PEMs would significantly reduce its practical impact. Applying the revised export treatment consistently across PEMs will provide clarity and ensure equitable treatment of similarly situated resources.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

6. Please submit your organization’s overall comments on Track 2.

SEIA appreciates CAISO’s recognition that existing DR constructs were designed around California-specific regulatory and operational structures and may not be well suited for WEIM and EDAM entities. Overly granular or CAISO-specific locational constructs can create unnecessary complexity without proportional reliability benefits for non-CAISO entities engaging in the regional markets.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

SEIA encourages CAISO to further evaluate the use of Custom Load Aggregation Points (CLAP) and, where appropriate, BAA-level aggregation for WEIM and EDAM DR resources. Providing flexible aggregation options will reduce barriers to entry.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Southern California Edison (SCE) appreciates the opportunity to comment on the March 13, 2026 Demand and Distributed Energy Market Integration (DDEMI) stakeholder meeting and the associated Track 1 Straw Proposal and Track 2 Issue Paper.  SCE’s comments are summarized as follows: 

Track 1- End-User Exports for Settlements Consideration: 
SCE does not support the Track 1 proposal to reflect end-user exports in demand response settlements as currently structured. Proxy Demand Resources (PDRs) and Reliability Demand Response Resources (RDRRs) are designed as load-curtailment resources, and compensating exports would introduce double compensation between wholesale market payments and retail export compensation mechanisms. 

Retail–Wholesale Coordination and Cost Causation: 
SCE is concerned that allowing wholesale compensation for exports that may also receive retail compensation under tariffs such as Net Energy Metering or the Net Billing Tariff would increase costs to load. Absent a clear, enforceable mechanism to track, net, or otherwise reconcile retail and wholesale compensation, the proposal raises fundamental cost causation and market integrity concerns that must be addressed jointly with the California Public Utilities Commission (CPUC) before further consideration. 

Performance Evaluation Methodologies (PEMs) and MGO: 
SCE does not support applying export treatment under the Metered Generator Output methodology or any other PEM. 

Preservation of Existing Demand Response Constructs: 
SCE supports preserving the integrity and predictability of existing CAISO demand response constructs and does not support modifying current programs to accommodate WEIM or EDAM BAA considerations if such changes would affect CAISO program design or operations. If alternative reliability-triggered demand response capabilities are needed for other BAAs, SCE believes separate, tailored products should be considered rather than retrofitting the existing CAISO RDRR construct. 

2. Please submit your organization’s overall comments on Track 1.

SCE does not support the Track 1 proposal to reflect end-user exports in demand response settlements as currently structured. Proxy Demand Resources (PDRs) are designed as load curtailment resources, not as supply-side or hybrid generation resources, and the proposal would materially alter that construct, particularly the risk of double compensation. Because these resources would receive both a wholesale compensation for the counted exported energy and the utility retail customers participating in Net Energy Metering or other retail compensation mechanisms, such as the Net Billing Tariff, may also receive compensation under their retail tariff. Allowing wholesale compensation for exports that are also receiving retail compensation would increase costs to load. Absent a clear, enforceable mechanism to track and net retail and wholesale compensation, SCE believes the proposal is inconsistent with sound market design and cost causation principles.  

It appears CAISO’s proposal of changing the Metered Generator Output (MGO) methodology to account for exports would be the easiest path forward to appease the large number of new stakeholders that have joined this initiative to offer comments in support; however, it would be inappropriate to advance this proposal without considering the financial impact to load. If this proposal were to move forward, this would undermine the entire Wholesale Distribution Access Tariff (WDAT) process which includes supply-side requirements and deliverability obligations. It would also put into question whether Reliability Demand Response Resources (RDRRs), also a load curtailment resource, should qualify for exported energy while on a retail program/rate that already provides incentives for the customer.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

SCE does not support applying the proposed export treatment to MGO or any other performance evaluation methodologies (PEMs). Until the CAISO and CPUC address the double-compensation issue, export compensation would not be appropriate under MGO or other PEMs. The proposal does not demonstrate that alternative PEMs sufficiently address baseline distortion, export attribution, or retail-wholesale interaction risks. Accordingly, SCE recommends that no PEMs be modified to reflect exports unless the ISO resolves these foundational policy concerns.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

The PDR PEM and wholesale settlement method does not adequately address the retail and wholesale double compensation issue.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

SCE agrees that any customer exporting energy must have an approved interconnection agreement authorizing and allowing energy exports, such as under Rule 21; however, this requirement alone does not resolve the broader policy concerns raised by the proposal. Implementing and validating export eligibility would require new review processes, data integration, and system changes, introducing additional complexities and costs. The interconnection verification requirements needed to validate the authorization of exports should not impose operational burdens and costs without corresponding market benefits.

6. Please submit your organization’s overall comments on Track 2.

No comments.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

No comments.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

No comments.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

SCE does not support modifications to the existing RDRR construct if such changes would affect current CAISO program design or operations. If WEIM or EDAM BAAs require alternative reliability-triggered demand response capabilities, CAISO should consider developing a separate product tailored to those needs rather than retrofitting RDRR. Preserving the integrity and predictability of existing CAISO demand response resources should remain a priority.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

No comments.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

As mentioned in SCE’s previous comments, SCE supports removal of the 100 MW discrete dispatch limit because it is impractical to divide thousands of customers into multiple resources to stay under the 100 MW limit.  The exception criteria should be modified to accommodate all large aggregated demand response portfolios.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

SCE has multiple proposals that were not seen in the recent issue paper and straw proposal. The following proposals were mentioned in previous stakeholder comments.  These proposals are the following: 

1. Discrete Reliability Demand Response Resources (RDRR) should be allowed to be derated or rerated across the entire range between Pmin and Pmax.  Although this may seem counter-intuitive, there are two operational realities upon which this request is based. 

   1. RDRRs are shared resources between SCE’s reliability/transmission function and SCE’s scheduling coordinator/marketing function.  When an RDRR is dispatched via the market, the Scheduling Coordinator (SC) must dispatch the entire resource. However, when an RDRR is dispatched by the reliability side, they do not necessarily need to dispatch the entire resource. In such cases, the SC is unable to accurately represent the remaining quantity of RDRR MW available to the market. 

   2. Available MW for some RDRRs are weather dependent. Without the ability to partially derate, this can result in a skewed representation of the quantity of MW available to the market. 

2. When CAISO enables RDRR resources into CAISO markets, they should also notify the Market Participants (the Scheduling Coordinators) directly.  Currently, CAISO Operations provides this notification to the reliability side of SCE (Grid Control), which has no action to take based on this notification.  Since enabling and dispatching RDRR resources via the CAISO market is a market function (e.g. SCE’s Energy Procurement & Market organization), CAISO should be providing notifications to the Market Participants at the same time notification is sent to SCE’s Grid Control. 

3. The market should use the startup times registered in the master file for RDRR start-up instead of hard-coded start up times which are incorrectly calculated as a function of the 5/15/60 bid option.  Hard coded start-up times may be appropriate for PDRs, but they are not appropriate for RDRRs. 

4. CAISO should implement a meaningful Resource ID naming convention for RDRRs. Currently, it is challenging for scheduling coordinators to identify which Resource ID corresponds to each Demand Response program due to the lack of clarity in CAISO’s naming convention. For example, SCE’s RDRR portfolio includes multiple programs such as the Summer Discount Plan (SDP), Smart Energy Program (SEP), Agricultural and Pumping Interruptible (API), and Base Interruptible Program (BIP). At a minimum, CAISO should include the program acronym in the Resource ID or allow scheduling coordinators to create their own Resource IDs.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

The State Water Contractors (SWC) appreciate the opportunity to comment on the Demand and Distributed Energy Market Integration (DDEMI) draft Straw Proposal (Straw Proposal). SWC also appreciates the time and effort CAISO staff and stakeholders have dedicated since 2025 and recognize this is a multi-year effort that will ensure flexible resources reliably, efficiently, and equitably.  

SWC supports CAISO's stated goal of focusing on near-term and implementable improvements. Consistent with that priority, SWC recommended in last year's Discussion Paper that CAISO move forward with implementing real-time load bidding and full participation for participating loads.

SWC would have preferred these initiatives to be considered as part of this initial Straw Proposal and looks forward to continuing to engage with CAISO staff through the working group to be established later this year.

SWC respectfully requests that the working group build upon — rather than restart — the extensive work already done by the California Department of Water Resources, stakeholders, and CAISO staff throughout 2025.

SWC would request inclusion in the working group and looks forward to future discussions on these topics.

2. Please submit your organization’s overall comments on Track 1.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

6. Please submit your organization’s overall comments on Track 2.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Sunrun appreciates CAISO’s work developing the DDEMI Straw Proposal, and we strongly support the inclusion of modifying PDR to allow end-user exports in Track 1. Overall, Sunrun sees potential for PDR to be modified to include exports from storage. However, the Straw Proposal as written today will not enable behind-the-meter (BTM) resources to fully contribute to the grid because Staff is proposing that aggregations as a whole not be allowed to net export. 

In order to fully realize the potentials of generating resources, particularly BTM storage, aggregations will need to be export enabled. While some aggregations will include a mix of customers with different types of DERs, it is likely that many aggregations will comprise only or majority storage resources that can all export. During times when these aggregations are dispatched, it is likely that the vast majority of customers would be net exporters in order to maximize the energy and capacity provided to CAISO.

By preventing the PDR aggregation as a whole from being a net exporter, CAISO is functionally changing very little from the status quo today. These storage aggregations will still be limited by their own customer load. To unlock additional capacity for the benefit of California, CAISO should seek to allow these aggregations to export as a whole.

CAISO has stated that the reasons for requiring PDRs to remain net importers is to “[Ensure] that the geography of the curtailment behavior corresponds to market topology. It also ensures unmodeled congestion is not created by PDR dispatches. Additionally, since sub-LAPs nest within DLAPs, this new aggregated limit ensures that PDR dispatch does not inadvertently orchestrate the behavior of behind-the-meter resources in ways that could create new constraints or reliability concerns on the distribution system.” However, this concern seems more aimed at areas where the sub-LAP as a whole becomes a net exporter or creates congestion on the distribution system because there is insufficient load to absorb the exports. While Sunrun understands this concern, the CAISO should develop tools that address the specific reliability issues. This could include measures to ensure that sub-LAPs are not net exporters or other necessary technical measures. Limiting aggregations so that they cannot be net exporters is not needed to achieve this goal.

2. Please submit your organization’s overall comments on Track 1.

Sunrun strongly supports BTM resource exports being included in Track 1. 
 

Sunrun also recommends that the CAISO discuss the below problem statements that are currently not included in Track 1. One of these problem statements is categorized under PDR issues (Topic 4), but others are categorized under Distributed Energy Resource Participation (Topic 5) but are relevant when discussing exporting PDRs. These include:

• 4.2. Current metering requirements for PDR restrict the ability to use device-level metering. Requiring revenue-grade meters (with ANSI C12) on each individual resource within an aggregation creates significant administrative and cost barriers.

• 5.2. DERP does not allow NEM/NBT resources to participate, and because most BTM batteries are interconnected through Rule 21 as NEM/NBT resources, they are ineligible to participate in DER aggregations.

• 1.3. BTM device-level measurement is not recognized for use in developing baselines for PEM options. Performance evaluations depend on energy measurement (load and generation) and don’t recognize non-energy metered technologies contributions to load reduction calculation.

Metering Accuracy (4.2)

Currently, the straw proposal for Track 1 envisions only discussing problem statement 4.1 on exporting resources in PDR, but device-level metering and metering accuracy is a critical aspect of enabling the full participation of these storage resources.

The meter-generator output (MGO) model was developed for generators like storage assets, but metering accuracy requirements often prevent aggregations from using this PEM. Sunrun agrees that accuracy in CAISO wholesale markets is critical. However, for PDR resources, it is most important that settlement is accurate at the aggregation level, not necessarily at the device level.

Sunrun recommends that metering accuracy requirements and solutions to this Problem Statement be discussed in Track 1 of this initiative.

Retail Tariff Participation (5.2)

Fundamentally, almost all BTM storage resources in California are participating in a form of Net Energy Metering or Net Billing Tariff. There are very few customers, especially in the residential segment, that are not on a retail tariff that compensates for exports. It is critical that exporting PDR resources be allowed to remain on retail tariffs. Otherwise, participation from these resources in the wholesale market will not expand. 

CAISO market participation should only compensate for incremental energy that is provided above retail rate dispatch signals. CAISO already considers this in existing baselines and performance evaluation measurement methodologies.
 

Device Level Registration (1.3)

Sunrun recommends that device level registration be discussed in Track 1 with respect to PDR. Measuring performance at the device, especially for storage assets, ensures that these resources are being compensated for the energy they are providing to the grid, instead of being over- or under-valued due to variations in customer load that are not being driven by CAISO dispatch. 

Measurement at the device level might also impact some elements of the Track 1 straw proposal. For example, if CAISO would like to enable device-level measurement for more accurate performance measurement, it should consider whether policies that require aggregations to be net importers would be beneficial. Therefore, the Track 1 Straw Proposal would benefit from explicit consideration of device-level registration and measurement.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

All PEMs should allow for exports from customer-sited resources. Sunrun does not see any reason to limit this proposal only to aggregations choosing the MGO PEM. As discussed by CAISO during the workshop, the MGO option is not the most common PEM in PDR today, with most aggregations using day-matching methodologies. The methodology in the Straw Proposal, even with the modifications discussed by Sunrun and other stakeholders, could easily be applied to day-matching PEMs or other baseline methodologies outside of MGO.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

Sunrun believes that PDR aggregations should be allowed to export. Therefore, considerations for zeroing out individual exporting customers would not apply in Sunrun’s proposal. 

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Sunrun agrees that all exporting customers should have an approved interconnection agreement with their utility distribution company that allows for export. All resources must abide by the terms of their interconnection agreement to export safely.

6. Please submit your organization’s overall comments on Track 2.

Sunrun doesn't have comments on this topic.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

Sunrun doesn't have comments on this topic.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

Sunrun doesn't have comments on this topic.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

Sunrun doesn't have comments on this topic.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

Sunrun doesn't have comments on this topic.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

Sunrun doesn't have comments on this topic.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

Sunrun doesn't have comments on this topic.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

2. Please submit your organization’s overall comments on Track 1.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

6. Please submit your organization’s overall comments on Track 2.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Voltus appreciates CAISO’s ongoing efforts related to DDEMI, most recently with respect to the thorough presentation of content and facilitation of stakeholder discussion on March 13, 2026, as well as the Track 1 Straw Proposal and Track 2 Issue Paper. Overall, we are encouraged by the alignment forming amongst the stakeholder community and CAISO with respect to how the DDEMI Guiding Principles are being reflected broadly in the identification and prioritization of the various issues.

We also recognize the real constraints faced by the ISO with respect to how many issues can be prioritized and implemented in the very near-term, and to the extent new systems, processes, and procedures (up to and including Tariff changes) are required, that will necessitate tradeoffs in terms of the quantity of issues than can be addressed in the immediate term. To this end, our main feedback pertaining to the March 13 meeting and discussion relates to considering inclusion of device-level telemetry device-level settlement in Track 1, as our position is that it may only require modest changes to PEMs and BPMs, provided that meter accuracy requirements of the Tariff can be satisfied.

2. Please submit your organization’s overall comments on Track 1.

Voltus strongly supports the Track 1 Straw Proposal to recognize end-user exports within the aggregation, specifically for customers who are already approved for export onto the distribution system. This is an essential step to paving the way for a large quantity of existing and future behind-the-meter (BTM) resources to participate in the market, and we commend CAISO for recognizing the importance of this issue and its inclusion in Track 1. We also support the focus on reforming the PDR participation model over DERA, given that it will build upon the success of PDR in that it is intended to facilitate registration of aggregations of many end users in an administratively efficient manner.

However, we are concerned that by limiting net export at the resource level, the opportunity to access significant new capacity will be limited and may result in unintended consequences. One example would be if an SC has a large portfolio of net-exporting resources, they would be incentivized to recruit large loads to enroll in the market in a manner that requires the large loads to remain passive and unresponsive to DR dispatches, effectively diluting the overall resource performance (and likely making it less predictable). Instead of zeroing-out net export at the resource level, we propose limiting exports in such a way that ensures no net export at the Sublap level.

We understand the concern of the CAISO to ensure that DR resources continue to represent aggregate demand curtailment and do not create new reliability constraints or reliability concerns on the distribution system. To address this, Voltus proposes the following solution.

Net PDR export capacity reservation concept

To ensure there are no net exports at the T&D interface, and/or that other deliverability concerns are mitigated, we offer the following straw proposal for consideration, as a way for CAISO to establish a basic net export capacity reservation system, defined by the following characteristics:

• SC’s define their net-export resources with a specific tag in the Resource Data Template. (RDT), and define the expected quantity of net export MW in the RDT similar to the MAX_GEN field, perhaps named “MAX_PDR_NET_EXP” which reflects the maximum expected net exported power capability of that PDR.
• CAISO establishes a maximum total allowed net export MW quantity within a given sublap for all such registered net-exporting PDRs.
• CAISO would review and compare the sum of all net-exporting PDRs’ MAX_PDR_NET_EXP MW in RDT submissions up to that point against the total sublap capacity allotted for this purpose
• SCs would be allotted new PDR net export reservation capacity on a first-come, first-served basis, defined by CAISO acceptance of the RDT
• SCs could be responsible for submitting a quarterly ex-post performance report, demonstrating they delivered at least 50% of the claimed ‘nameplate’ net export capability of the PDRs in their RDT in a one-hour interval during the preceding quarter.
• If SCs do not establish this 50% minimum net export threshold vs. their claimed net export capacity, the PDR must be de-rated and RDT must be updated in the following quarter (or CAISO may reject the resource) such that its net export capacity is no greater than 200% of the latest quarterly test result
• To provide transparency to market participants, it would be ideal for CAISO to publish the reservation capacity, perhaps in a manner similar to PG&E’s Option S reservation system or the SGIP program

The benefit of this structure is it relies upon largely familiar systems and processes and we believe would be a reasonable first step. Later on, perhaps aggregators could have the option to provide CAISO with telemetry of their resources, which could more quickly demonstrate the full utilization of the resource without ongoing reporting requirements. With this framework, it will ensure no new reliability constraints or other deliverability concerns arise, because CAISO is able to methodically control and observe the total aggregate net exporting capacity at the sublap level.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

This change to enable net export should apply to all PEMs. In many instances, Voltus has recruited C+I DR customers for whom curtailment plus the effect of a BTM storage asset could deliver net exporting capability. In our experience, it is largely for lack of a market participation model that provides export credit for storage that has led to little coordination between load curtailment and storage deployment.  With the inclusion of counting net exports for resources using day-matching PEMs, this pathway to additional storage deployment is made possible. Putting it another way, by limiting this change to MGO, it inherently limits the types of customers that may benefit, narrowing the pool of available additional resources, because many customers may be able to combine load curtailment with BTM storage dispatch.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

This unnecessary as it should mainly be the concern of the Scheduling Coordinator and not primarily the concern of the CAISO, since this primarily relates to how end-use customers contract with their SCs.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Voltus supports the proposal for only customers who have approved interconnection for export onto the distribution system.

6. Please submit your organization’s overall comments on Track 2.

Voltus’s comments on Track 2 are mainly pertinent to question 8 below.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

Voltus has no comments on this topic at this time.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

Voltus supports any and all efforts to encourage participation of flexible loads in markets. To this end, Voltus has found it difficult to enroll interested and willing customers in BAAs for which there is no pre-existing enrollment system for 3^rd party aggregations. As a market participant and as a 3^rd party aggregator, we are supportive of standardized structures as much as possible, and for this reason DRRS would be a good option. However, to the extent BAAs have pre-existing systems, as long as they meet standards developed in Track 2, Voltus is supportive of BAA-managed systems as well.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

Voltus has no comments on this topic at this time.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

Voltus has no comments on this topic at this time.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

Voltus has no comments on this topic at this time.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

Vote Solar is very pleased with the CAISO’s decision to prioritize the resolution of the opportunity to export of power by individual customers within the proxy demand program. The proposed change will enable a significant increase in the capacity and energy that can be provided to the CAISO system through the Proxy Demand Program.  Vote Solar is hopeful that this proposal can be brought to the CAISO Board of Governors by August 2026.

Vote Solar has no comments on Track 2.   

2. Please submit your organization’s overall comments on Track 1.

Vote Solar supports the straw proposal. We agree the recommendation that Scheduling Coordinators no longer be required to zero out the meter data of individual end-use customer who export energy onto the grid during a dispatch interval.

We find it reasonable for the CAISO to establish a new “floor” at the aggregated resource level so that the unmodeled congestion is not created on the transmission system.  We understand the a PDR participant can add managed load to avoid falling below the “floor”.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

Yes. The proposal should apply to all performance evaluating methodologies and not be limited to metered generation output.  This application across PEMS will address the underutilization of existing baselines and modify PEMs to recognize energy exports and improve the accuracy of using for modern, distributed resources.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

 Vote Solar recommends that the CAISO leave Proxy Demand Response providers and their Schedule Coordinators to determine how to handle the ultimate settlement if it hits the floor and its net export is zeroed out.  There is no need for the CAISO to be involved in the settlement between a proxy demand provider and individual customers.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

Vote Solar understands that exporting customers must have an interconnection agreement that allows them to export to the distribution system.  It should be an administratively simple process for the utility distribution company to confirm to the CAISO that a customer has such an agreement. Verifications of interconnection agreements should take no longer than three days.

6. Please submit your organization’s overall comments on Track 2.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

1. Please provide your organization’s feedback on the DDEMI meeting discussion on March 13, 2026 and “Demand and Distributed Energy Market Integration Track 1: Straw Proposal: Reflecting End-User Exports in Demand Response and Track 2: Demand Flexibility Enhancements” paper.

PacifiCorp, Portland General Electric, and the Sacramento Municipal Utility District (collectively, the WEIM/EDAM Participants) appreciate the CAISO’s efforts in this initiative and submit the comments below.

The Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) Participants appreciate the discussion and work the CAISO has done thus far regarding demand response (DR) reform. The Track 1 Straw Proposal and Track 2 Issue Paper reflect some of the concerns brought forth throughout the working group and we believe the conversations are moving forward in the right direction. The WEIM/EDAM Participants support the flexibility in options the CAISO has provided in Track 2 and look forward to further collaboration in this effort with the considerations provided below.

2. Please submit your organization’s overall comments on Track 1.

The WEIM/EDAM Participants believe the Performance Evaluation Methodology (PEM) update to resolve for DR programs that have the potential for exporting provides additional flexibility. We understand the interest in Track 1 for Load Serving Entities (LSEs) within the CAISO’s Balancing Authority (BA), but from a WEIM/EDAM Participant perspective, our most critical concern with the PEM construct is not addressed. The WEIM/EDAM participants acknowledge that the CAISO’s straw proposal and issue paper does provide a track for our concerns to be addressed (Track 2), however, the timeline for when that work will be done does not allow for changes to be implemented for this DR season based on the projected timeline of activities as proposed. The concerns brought forth in comments provided on December 17, 2025, are the roadblocks and challenges faced when attempting to integrate DR in the CAISO markets for WEIM and EDAM participation. Additional comments are provided in question 12.

3. Should the change in the straw proposal apply to all PEMs or be limited to MGO? Why or why not?

As an initial reaction to the proposed application for all PEMs where the CAISO proposed to create a new “floor” for resources that have the ability to export, it would be prudent to apply the change to all PEMs. However, this change warrants more discussion on the impacts, even if negligible. It was understood during the working group meeting on March 13, 2026, that there are bandwidth limitations for a holistic change to all PEMs. The WEIM/EDAM Participants believe that if the CAISO is going down the route of adjusting tariff language for PEMs, it would be prudent to do a comprehensive PEM reform as it may increase the flexibility for near-term DR participation.

4. Are there considerations not mentioned in the paper for how individual end-use customers within a PDR should be treated (e.g., specifying which individual exporting customers should be zeroed out, or applying a pro-rata approach across all customers)?

See our responses to comments 2 and 12.

5. Provide your organization’s feedback regarding the proposal for exporting customers to have an approved interconnection for export onto the distribution system.

See our responses to comments 2 and 12.

6. Please submit your organization’s overall comments on Track 2.

While we appreciate the proposals, neither Track 1 nor Track 2 address our critical concerns for being able to participate our DR programs for WEIM and EDAM. For additional details, see our response to question 12.

7. What locational construct, such as sub-LAP, CLAP, or BAA-level aggregation, facilitate reliable demand response market participation in WEIM/EDAM BAAs?

The WEIM/EDAM Participants appreciate the CAISO’s willingness to offer choices for modeling WEIM/EDAM DR programs as resources under the current sub-locational aggregation point (LAP), Balancing Authority Area (BAA)-level aggregation, and/or Custom LAP (CLAP) level. Today, the sub-LAP framework is the status quo for DR resources and the WEIM/EDAM Participants believe having flexibility in modeling would assist in some of the hurdles currently faced for registering DR resources. After deliberation, the path of preference would be for further exploring the CLAPs. This path would give a level of granularity that still enables the market to continue managing locational congestion which the BAA-level aggregation level does not appear to provide. However, in the event that one program works best under the CLAP or BAA-level, our understanding is that it is on the table for all these options to remain. For example, if a market participant prefers one program under the CLAP and another at the BAA-level, would the CAISO allow for this instance to occur.

8. Is DRRS suitable for demand response resources outside the CAISO BAA, or should other BAA-managed registration systems be explored? Why or why not?

The WEIM/EDAM Participants strongly agree that a BA managed system move forward in this policy process. Utilities have their own Demand Response Reporting System (DRRS)-like processes which are a basic requirement and function of the Virtual Power Plant/Distributed Energy Resource Management System platforms and so leveraging pre-existing processes is preferred, while packaging to the CAISO in a standardized manner. Further, given that customer renewal contracts are in flux each year, as customers enroll and disenroll themselves, there needs to be some flexibility for updating customer-level data to the CAISO. Notwithstanding, it would be overly burdensome for an WEIM/EDAM participant to manage DRRS data in multiple systems and would unnecessarily expose customer information to additional systems with no benefit to CAISO’s market operations. The WEIM/EDAM Participants have strict policies they must adhere to under their own state jurisdictions, along with general market policies to provide CAISO with the highly accurate data associated with resources.

9. Does your organization support the ISO pursuing modifications to the existing RDRR construct to capture WEIM/EDAM BAA considerations? What modifications would you recommend and why? Alternatively, should the ISO consider developing a new reliability-triggered demand response product applicable to all BAAs?

The existing RDRR model characteristics are specific to meet CAISO’s needs and requirements. If we were to pursue a similar model, we would prefer developing a WEIM/EDAM specific DR product that avoids confusion with the existing CAISO specific model and avoid using ‘reliability’ in the name or design language of this newly proposed model. The new model would count towards the EDAM Resource Sufficiency Evaluation (RSE) for the exclusive use of the submitting entity and would therefore only be dispatched at some defined threshold trigger to either alleviate infeasibilities and/or possibly for heavy congestion at our BA level, as these programs may have restrictions preventing them from supporting other BAs or entities.

We would need to further work on significant design changes and would like to better understand the different options of how these resources operate, what will trigger them, who sets that/those triggers, are the trigger thresholds adjustable, if so, how are they adjusted, etc.

10. Do the proposed large load participation pathways adequately reflect the capabilities and preferences of large load? If not, what changes would you recommend and why? Is there other industry guidance or participation frameworks the ISO should be aware of?

We believe there may be additional opportunities for improvement, regarding how large loads are changing. The Pacific Northwest (PNW) is also experiencing tremendous load growth. The load growth is driving various forms of flexibility. The PNW entities are experiencing potential large load customers offering everything from giant behind the meter batteries and diesel generators to providing standalone batteries for the utility to dispatch. These flexible resources could be as small as 1 MW and as large as several hundred MWs. There can be complexities around how the resources are dispatched, depending upon the agreement, such as whether it can only be dispatched for local congestion, or more broadly used for overall system congestion and high prices, or bid into the market as a regular participating resource while being on a retail tariff. We would like to discuss the different possible scenarios along with what current models they would fit into, and how do those models operate.

For example, in the scenario where the flexible load could only be dispatched to resolve local congestion, perhaps an RDRR-like model could be modified in a way that identified local congestion at a load pocket and dispatched the data centers battery. However, we’d also need a model that could also later recharge the battery. Ideally this could be modeled like the Non-Generator Resource (NGR) model we use for participating batteries.  Again, for entities that participate in EDAM and WEIM, we would propose different naming of the model – we would not want ‘reliability’ language tied to a resource model that performs like this.

11. Should the exception criteria for the 100 MW RDRR discrete dispatch limit be modified to better accommodate large aggregated demand response portfolios? Why or why not?

No comment.

12. Please provide any additional comments, feedback, or examples. You may upload examples or data using the Attachments field below.

Supply-side

While there are many valuable ideas and improvements currently proposed in this initiative, we would like to redirect focus to the foundational needs of WEIM and EDAM participants. Specifically, WEIM and EDAM participants require a method to meaningfully represent and participate a variety of Flexible Load and DR programs. Our objective is to align DR participation models more closely with those applicable to generating resources or Non-Generator Resources (NGRs). The primary issues currently hindering DR participation in the market are:

1. PEMs, Metering & Telemetry Requirements (Critical – Blocker)

The WEIM/EDAM Participants appreciate the CAISO’s recognition that the existing PEM framework has become too rigid to accommodate demand-side bidding and behind-the-meter (BTM) resources.

The WEIM/EDAM Participants strongly encourage the CAISO to pursue a FERC filing to modernize the 2010 precedent that requires PEMs to be hard coded in the CAISO tariff. That legacy requirement, while appropriate when performance methodologies were first standardized, now limits innovation and regional harmonization. A modified framework would preserve FERC oversight, maintain transparency, and allow the CAISO to respond to technological and programmatic evolution without repeated tariff filings. The WEIM/EDAM Participants envision this framework functioning similarly to how the CAISO administers metering policies today – through clearly documented standards, subject to CAISO approval and audit, but without the inflexibility of codifying each methodology in the CAISO tariff. The WEIM/EDAM Participants understand the continued use of PEMs as a settlement and verification tool and seek a model that allows participants to select or design the PEM most effective for their resource mix and regulatory environment, consistent with CAISO-approved standards. This flexible approach would enable BAAs to determine whether a PEM, direct metering, or a hybrid approach best captures true performance, without undermining consistency or reliability.

The WEIM/EDAM Participants request the CAISO either enhance the current proxy demand response (PDR) participation model or create a new one that works for broader DR/DER programs. The WEIM/EDAM Participants found there to be a limitation in the registration of DR programs as PDRs, which extends beyond the selection of a PEM during the registration process. The WEIM/EDAM Participants believe the PDR-based telemetry and metering requirements, which are codified in the CAISO tariff, are not reflective of the operational realities of demand-side bidding and BTM programs currently implemented within non-CAISO BAA.

For many of these programs, particularly those exceeding 10 MW of aggregated capability, the requirement to provide direct telemetry modeled after the PDR construct is impractical. These participants rely instead on validated metering and statistically sound PEMs to estimate performance for settlement and verification. The CAISO should recognize that regional market participants external to the CAISO BAA participate or operate in BAAs whose direct responsibility is to both maintain reliability and have a vested interest in maintaining accurate performance evaluation. Accordingly, such market participants should be afforded the flexibility to propose and justify PEMs that align with their local regulatory requirements, data availability, and customer-program design, subject to CAISO approval.

Without this modernization, WEIM/EDAM Participants will inherit a PEM framework that cannot accommodate DR programs designed around each participant’s regional operating realities and current business practices. Consequences of unsuccessfully registering DR programs, which remain whether in WEIM and/or EDAM, will result in a limitation of real capacity that could be base/self-scheduled or dispatched if the need arises. Evolving the market based on the needs of market participation in the CAISO markets is prudent.

2.  Operational Characteristics – the current construct does not allow for derates (Very High Priority)

As stated in section 15 of the Business Practice Manual (BPM) for DR:

“A PDR, RDRR or PDR-LSR is allowed to have outages, but will be limited to updates to its ramp rates or to modifying its capacity to 0.  PDR, RDRR and PDR-LSR are all-or-nothing resources, which limits how much such resources can be derated.  PDR, RDRR, and PDR-LSR are also prevented from submitting a rerate of their PMin.  OMS has been updated to enforce these business rules.

OMS has been updated to permit a PDR, RDRR or PDR-LSR to submit only PMax derates or Ramp Rate derates.  Any other data entered in OMS through either the UI or API for a PDR, RDRR, or PDR-LSR Resource ID shall return an error message.  OMS also has validation to restrict PMax derates entries for PDR and RDRR Resource IDs to be only 0 MW.  A PMax derate is used to indicate a day should not be used in the baseline calculation.  Since a day is either valid or invalid, the only PMAX derate permitted for PDR and PDR-LSR is derate to 0 MW’s (i.e., a PDR is either 100% available or 0% available, there are no partial derates for PDRs and PDR-LSRs).Cause codes are no longer required when submitting outages.

In order to keep a Resource ID active and reduce the need to make updates to the CAISO Master File, the DRP using its scheduling coordinator can submit extended outages to derate its resource to 0 MW when it does not wish to participate in the market.  Please see Operating Procedure 3220 for more information”

The WEIM/EDAM Participants would like to update DR participating models with outage management flexibility similar to any other bulk generation in order to capture the dynamism of our DR programs. The current outage management of “all-or-nothing” is too blunt to capture the dynamic characteristics of our DR Programs (e.g. customer entering and exiting a program, outages to specific area of our distribution system affecting certain participating customers, and DR programs where performance is related to weather conditions).

3. Registration and Scalability (High Priority)

Comments provided in question 8 – WEIM and EDAM entities need flexibility with DR registration.

4. BPM and Documentation clarifications:

Further, the WEIM/EDAM Participants request the CAISO revise the current BPMs to clearly delineate and explicitly identify the requirements applicable to WEIM/EDAM Participants, as distinct from those applicable solely to CAISO BA entities. As currently structured, the BPMs intermingle CAISO BA-specific obligations with requirements applicable to WEIM/EDAM Participants, without annotation, differentiation, or cross-reference to indicate which provisions govern which class of participant. This lack of structural clarity creates unnecessary compliance risk and administrative burden for WEIM/EDAM Participants, who must independently parse documentation not designed with their participation model in mind. CAISO should adopt consistent conventions to delineate between CAISO BA and WEIM/EDAM Entities, such as participant-class-specific headings, applicability statements at the section level, or dedicated annexes, to ensure that all participants can readily identify the full scope of their obligations without ambiguity.

While we recognize and appreciate the proposals put forward, it is our collective view that the current proposal does not adequately resolve the primary barriers to WEIM and EDAM entity participation in DR programs.

Concerns with the Load Forecast Adjustment (LFA) Model

In the absence of a framework that treats DR resources similarly to generators, our best option is the LFA model (where adjustments are submitted to ALFS and incorporated in the forecast). While the LFA model has seen notable improvements, it continues to present significant challenges, including:

• Limited data availability for LFA events, including:
  • No settlements data
  • No records of schedule changes or associated impacts
• Current tools and processes do not currently handle this sort of data
  • Any data proposed under the current framework would be delivered through new methods requiring additional programming and processing
• The proposed LFA API to ALFS does not return event data to the BA, leaving EDAM entities reliant on data provided by Scheduling Coordinators (SCs)
• EDAM systems would need to process LFA details separately, using internal calculations to properly allocate LFA adjustments to LSEs within the BA who own those programs

Until the critical and high-priority barriers to participation are resolved, the LFA model remains the most viable option for WEIM and EDAM entities. However, the current proposal to submit LFA data to ALFS without accompanying data retrieval capabilities introduces additional challenges and risks. We must be able to accurately reflect DR events and credit the appropriate BA — the current proposal does not provide BAs with the level of data necessary to perform this function.

At minimum, BAs must have the ability to retrieve the following for each event:

• The original, unadjusted load forecast for the applicable hour
• The adjusted load forecast
• The amount of the adjustment
• The LSE for which the adjustment was made

Without this data from CAISO, EDAM BAs will be dependent on information provided directly by LSE merchants to make the necessary adjustments in their EDAM systems — an untenable position for accurate and auditable market participation.

We respectfully request that these issues be assigned high priority and incorporated into the scope of Track 1 of the DDEMI working group.