Comments on May 18, session 14 on second revised straw proposal on Uplift and Default Energy Bids (DEB), Outage Management

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

ACP-California shares concerns that were voiced by stakeholders during recent meetings regarding the use of multiples and other elements proposed for the redesigned DEB. Specifically, we share concerns about use of multipliers below 1.0 (e.g., 0.6), which could create result in problematic instances of storage resources being discharged. We encourage CAISO to further consider these implications and reevaluate the use of multipliers below 1.0.

ACP-California also supports comments from other stakeholders that a TOD multiplier should be updated more than yearly to appropriately capture seasonal shifts in solar and wind patterns. Additionally, we encourage CAISO to explore the use of trading hubs for application of the scalers, rather than specific points on the system.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

ACP-California appreciates the breakdown of the NGR bidding concept and supports CAISO staff refining the concept in the upcoming Straw Proposal next month. In general, ACP-CA directionally supports technical improvements to modeling and participating BESS resources in regional energy markets.

Accordingly, ACP-CA is interested in reviewing a more fleshed out proposal in the next Straw Proposal. ACP-CA membership is interested in design enhancements that balance refinement with the introduction of complex structures that require significant and ongoing operator training.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

ACP-California generally supports CAISO’s plan to implement automation of outage change requests, as well as the plan to test power minimum capabilities on test energy cards, as part of the new resource implementation process. ACP-California supports these enhancements since in most cases, the outage change request will be automatically accepted – but still reviewed, studied, etc., by reliability coordinators, engineers, and ISO staff in service of reliability procedures. Because these key elements remain, the enhancement improves visibility for all market participants, while also preserving flexibility for market participants to make dynamic changes as needed.

ACP-California supports the request by stakeholders for additional discussion on various topics they identified as concerning or requiring additional attention, including study queue prioritization, UCAP calculations and work codes, and RAAIM exposure. We would appreciate further discussion of these topics in the June 30th Straw Proposal and at the July stakeholder meeting.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

ACP-California supports CAISO’s proposed solution for nonlinearity and understands that the Spring 2027 timeline represents an aggressive timeline for CAISO staff. We appreciate CAISO prioritizing this issue and working to implement a solution that has had strong stakeholder support as quickly as feasible.

ACP-California broadly supports the CAISO’s proposal to transition the feasible operating region from a rectangular model to an irregular hexagon to represent storage nonlinearity. Grounding this solution in Master File data fields (specifically the four new parameters for minimum and maximum nonlinear energy limits and their diminished power outputs) is a robust approach. The proposed approach addresses many of the issues ACP-California and others identified earlier in the stakeholder process.

ACP-California appreciates the work required to achieve a Spring 2027 implementation. While a faster rollout would be ideal, we recognize that reshaping the market optimization to include these new data points (and ensuring consistent application across both day-ahead and real-time markets) requires significant technical development and system testing.

While we understand the options available for storage operators in the interim, they are far from ideal. ACP-California is concerned that representing foldback range as “plant trouble” could have impacts for future UCAP calculations, which may or may not be appropriately accounted for. We would appreciate additional discussion and consideration of the interactions with UCAP at a future stakeholder meeting.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the California Independent System Operator’s (CAISO) May 18, 2026, stakeholder meeting and Revised Straw Proposal on outage management. In summary, the CAISO should:  

• Adopt a “time-of-day” storage default energy bid (DEB) that better reflects storage resource costs when real-time conditions deviate from day-ahead conditions;
• Further develop the “time-of-day” storage DEB proposal to inform how the CAISO will set the multipliers used to shape the storage DEBs; and
• Continue efforts to develop a modeled solution for reflecting foldback as soon as feasible.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

CalCCA supports the development of a “time-of-day” storage DEB to better reflect storage resource costs when real-time conditions deviate from day-ahead conditions. The CAISO’s proposed methodology would: (1) eliminate the energy cost component and include a gas floor; (2) scale day-ahead proxies based on the difference relative to real-time locational marginal prices; and (3) scale the DEB multiplier to conform with the hydro DEB and represent changing opportunity costs. CalCCA conceptually supports the methodology proposed, as it should better reflect changing real-time opportunity costs and minimize the challenges associated with using “stale” values. Additional development is necessary, however, to inform how the CAISO will set the multipliers used to shape the storage DEBs before CalCCA takes a position on the final design.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

CalCCA supports continued exploration of methodologies for storage resources and the market to more effectively manage state-of-charge. CalCCA appreciates the information provided during the stakeholder meeting regarding the non-generator resource bidding concept put forth by the Market Surveillance Committee. CalCCA will continue to explore this concept and other concepts presented for state-of-charge management before taking a position on the best path forward.  

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

CalCCA has no comments at this time.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

CalCCA supports the CAISO’s proposal to address nonlinearity through a modeled solution in the Master File. A modeled solution to reflect foldback in the market is the most robust and durable approach to reflecting non-linearity going forward.

Until the modeled solution is implemented, the CAISO states that market participants can limit their risk of entering the nonlinear range by only reflecting the state-of-charge range unaffected by foldback. If resources experience unavailability related to nonlinearity, the CAISO states the unavailability must be reflected through the plant trouble nature of work outage card. CalCCA’s interest in these interim actions is grounded in ensuring that California’s resource adequacy (RA) framework functions as intended, maintains investor confidence in storage, and preserves the reliability benefits of the state’s rapidly growing battery fleet. CalCCA understands the CAISO plans to address related RA issues within the Resource Adequacy Modeling and Program Design (RAMPD) initiative and agrees that there remain open RA-related issues related to nonlinearity.

Overall, within the RAMPD initiative the CAISO should allow a resource to show up to its Pmax provided the sum of the energy in each hour shown does not exceed the capability of the resource when foldback occurs. Given that the California Public Utilities Commission (CPUC) has moved to an hourly RA structure, and a storage resource can provide up to its Pmax in the four hours of its discharge, the CAISO should allow the resource to show its full capacity subject to its energy limitation. If this requires a change in the CAISO Tariff, the CAISO should proceed with a tariff filing at the Federal Energy Regulatory Commission to effectuate necessary changes that properly reflect the reliability contributions of storage while recognizing energy limitations. In addition, the CPUC and CAISO should ensure that if foldback is accounted for in the qualifying capacity value, it is not also counted against a resources unforced capacity value, and vice versa. 

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

CalCCA has no additional comments at this time.

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

The California Energy Storage Alliance (CESA) appreciates the opportunity to comment on the May 18, 2026, working group meeting.  CESA notes that both the default energy bid (DEB) changes and Market Surveillance Committee bidding concepts require additional discussion. Additionally, given the technical subject matter of the storage DEB, it would have been beneficial to have the presentation posted a week in advance of the stakeholder call.   

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

In summary, CESA is supportive of the storage DEB proposal guiding principles. CESA recommends that the storage DEB formula be consistent across all storage resources and that each multiplier be designed to address a specific issue independently. In addition, CAISO should analyze historical data of storage DEBs to understand which terms in the DEB formula are setting the DEB and evaluate how the DEB would change under the proposed changes in the DEB formula. Finally, CESA recommends that CAISO focus on the DEB issue for the next two working groups.  The large gap between the December/January and the May discussions on storage DEB hindered the ability of stakeholders to provide feedback as the proposal evolved. CESA believes CAISO can develop and adopt a well-designed storage DEB framework if it maintains momentum on this issue.

CESA believes that the storage DEB draft straw proposal guiding principles, if adhered to, will greatly improve the real-time storage DEB. The recognition that real-time opportunity costs are independent of day-ahead prices and that mitigated bids must place storage resources in the correct position in the bid stack is promising. CESA notes that the correct bid stack position guiding principle applies to all storage resources whether in EDAM or WEIM-only which supports a similar methodology is needed for all storage resources. CESA provides its comments below on the proposed elements of the storage DEB changes.

Include the Gas Floor from the Hydro DEB

CESA supports including the gas floor from the hydro DEB in both the day-ahead and real-time DEB which will help correctly position storage resources in the bid stack when mitigated. 

CESA notes that the 1.1 multiplier is to recognize that the data inputs are an estimation.  The 1.1 multiplier was not empirically determined; however, it is applied across multiple DEBs to provide a common 10% adder to cover errors in the estimated costs.

Removal of Energy Cost

With the inclusion of the gas floor, it is unclear to CESA if the energy cost plus the variable storage cost will be the binding component of the storage DEB max formula. The question of whether do include or exclude the energy cost component should be answered empirically. CAISO should analyze historical storage DEBs to evaluate which terms of the day-ahead and real-time DEB max formula set the DEB.  CESA believes this analysis may provide empirical evidence that the energy cost is no longer a binding factor in establishing the day-ahead and real-time DEB and point to the need to remove the energy cost.

Apply a 1.4 Multiplier to Opportunity Cost in Day-Ahead DEB

CESA supports the proposal's effort to recognize and compensate storage charging opportunity costs; however, additional refinements are needed to ensure those costs are accurately reflected in market outcomes. While CESA recognizes that using a 1.4 multiplier for opportunity costs in day-ahead DEB would mirror the hydro DEB formulation, it is unclear why this would not be included in the real-time storage DEB.  The 1.4 multiplier for the hydro DEB was determined by analyzing differences between the short-term index prices and actual WEIM prices.  This 1.40 multiplier was based on analysis to ensure the hydro resource was not dispatched more than 4 hours per day in a range of 95-99% of the time based on modeling WEIM prices in various EIM BAAs compared to the representative bilateral hub prices.

CESA recognizes that the proposal does include a time-of-day (TOD) multiplier which attempts to replace the need for the opportunity-cost multiplier. However, it would be better to treat these as independent because they serve unique purposes in the DEB formula.  The opportunity cost multiplier ensures that the estimate of opportunity costs does not result in excessive real-time dispatch; whereas the TOD multiplier attempts to address changes in opportunity costs across the operating day.

Scale DA LMPs or DGAP prices in Real-Time DEB

CESA agrees with scaling the day-ahead opportunity costs to better reflect changes that can occur in the real-time market. To accomplish this, CAISO should perform a similar analysis performed when the hydro DEB was developed to calculate an appropriate scalar using historical data.  The appropriate scalar would ensure that storage resources are not dispatched earlier in the day and are uneconomic to recharge prior to the net load peak.

To improve alignment between EDAM storage resource and WEIM-only storage resources, the CAISO should consider using the resource trading hub for CAISO resources and the relevant DGAP for EDAM resources outside CAISO balancing authority area.

CESA looks forward to additional documentation on how the scalar is calculated. Also, any scalar should also consider the interactions with the TOD multiplier.  In prior comments, CESA has recommended the ability to modify the scalar dynamically if system conditions highly diverge from day-ahead.

Apply a 0.6 to 1.4 Time-of-Day Multiplier in Real-Time DEB

CESA recognizes that the opportunity cost of a storage resource could differ over the course of the day if the resource can perform multiple cycles per day. As CAISO’s example showed, the multiplier results in a higher DEB just before the morning and evening net load transitions. If a four-hour battery discharged within the four hours prior to the start of the evening peak, its ability or likelihood to recharge is less than if the battery was discharged eight hours prior to the start of the evening peak. 

However, CESA has concerns about implementation. The TOD multiplier approach assumes that real-time conditions are predictable such that an accurate TOD multiplier for a given hour can be calculated. Additional information is needed on how the TOD multiplier will be calculated and when it can be modified.

Lastly, CESA would not support any TOD multiplier that would reduce the real-time DEB below the day-ahead DEB. A multiplier below 1.0 would penalize storage resources in real-time relative to their day-ahead position, which CESA finds unacceptable.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

CESA appreciates the review of the MSC bidding concept. The MSC bidding concept would be a significant change from the current non-generator resource (NGR) bidding paradigm. CESA acknowledges that it highlighted the September 2020 MSC opinion in previous comments on the storage DEB.  CESA did so because the MSC provided an excellent explanation how opportunity costs can occur outside the market horizon, which is why those costs need to be included in energy bids. Otherwise, those costs are not reflected in the market optimization.

The MSC opinion also highlighted that “end effects” can be addressed by including an end-of-horizon SOC target and including a price to deviate from the SOC target. This modeling approach would change the current bidding paradigm. This will require a broad discussion with stakeholders regarding additional changes to storage bidding. For example, currently in the day-ahead market, different energy bids can be submitted for each hour.  Under the MSC proposal, would a single spread bid apply for each hour in the day-ahead market or could different end-of-horizon SOC prices be used to construct multiple spread bids?

CESA recommends CAISO focus on updating the storage DEB near term and discussing the MSC proposal and energy storage resource model later in the year.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

CESA supports the outage reporting enhancements. 

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

CESA supports modeling nonlinearity in the market optimization as soon as possible. Between now and Spring 2027, storage operators will be unable to offer capacity within the foldback region and receive revenues during tight system conditions without triggering RAAIM penalties. This creates a reliability risk since CAISO operators cannot access this capacity during tight system conditions. As a result, CESA continues to disagree with CAISO’s position that Plant Trouble is the appropriate nature of work during this interim period. 

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

No additional comments.

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

Comments on Storage Design and Modeling

Working Group Presentation - May 18, 2026

Department of Market Monitoring

June 5, 2026

Summary

The Department of Market Monitoring (DMM) appreciates the opportunity to comment on the Storage Design and Modeling working group presentation held on May 18, 2026.[1]

DMM supports the ISO’s proposal to incorporate a time-of-day multiplier into the storage default energy bid (DEB) to reflect how opportunity costs vary throughout the day. DMM has long argued that a theoretically sound storage DEB should vary for different hours of the day, since opportunity costs for storage resources change throughout the day based on upcoming prices and their ability to charge and discharge.

While DMM has shown that the current storage DEB performs well as an input to local market power mitigation, DMM agrees that it could be improved to more accurately reflect varying intraday opportunity costs for storage resources. DMM appreciates the ISO’s progress in proposing a DEB multiplier that more accurately reflects the hours with higher and lower opportunity costs, and DMM’s recent analysis shows that a simple time-of-day multiplier like the ISO is proposing could yield notable benefits.

DMM questions whether the inclusion of the gas floor component is appropriate as an input to estimate the marginal costs of storage resources. DMM believes the current storage DEB’s utilization of locational prices from previous market runs more directly reflects estimated opportunity costs and would likely incorporate the cost of gas-fired resources when applicable. DMM requests the ISO provide further justification for why the gas floor should be incorporated into the storage DEB formulation.

DMM generally supports other proposed enhancements to storage outage management and storage resource modeling as discussed in the ISO’s May 18 presentation. However, DMM continues to note that such enhancements should not be developed and pursued at the expense of comprehensive bid cost recovery (BCR) design enhancements for storage resources. The ISO’s May 18 presentation appears to suggest that other enhancements will be pursued before continuing work on storage BCR design, and that the ISO will “assess whether additional BCR changes are needed” after implementing such enhancements.[2] DMM disagrees with this approach and recommends the ISO continue to prioritize BCR design for storage resources independent and ahead of other storage market design changes.

Comments

A simple refinement to allow the storage DEB to vary across the day could yield significant benefits

DMM supports the ISO’s proposal to incorporate a time-of-day multiplier into the storage DEB formulation in order to more accurately reflect intraday opportunity costs. DMM has previously found that the current storage DEB framework performs well as an input to mitigation, and does not result in significant inefficient real-time dispatch when storage resources are mitigated.[3] However, DMM has long argued that a theoretically sound storage DEB should calculate marginal costs on an hourly basis, since opportunity costs change throughout the day based on upcoming prices and the resource’s ability to charge or discharge.[4] While an ideal storage DEB would vary hourly, DMM’s recent analysis indicates that even a simple time-of-day multiplier that raises and lowers the DEB during certain hours can yield significant improvements.[5] DMM recommends the ISO continue to develop refinements to the current storage DEB with a simple time-of-day multiplier that takes on values reflecting hours with higher and lower opportunity costs, rather than introducing more complex storage DEB design changes.

The time-of-day multiplier should be based on empirical analysis of how opportunity costs are higher and lower at different times of the day

DMM supports a time-of-day multiplier similar to the illustrative example provided by the ISO, but recommends a multiplier grounded in a more empirical basis. DMM’s previous analysis shows that the hour in which the higher DEB multiplier switches to the lower DEB multiplier can significantly impact the efficiency of battery schedules when batteries are subject to mitigation.[6] The determination of which hours have higher or lower multipliers should be based on empirical analysis to ensure the multipliers result in DEBs that accurately reflect the opportunity costs throughout the day without understating or overstating those costs, particularly in pivotal hours. DMM continues to recommend flexibility in the assignment of multiplier values across different hours as it is likely that the highest priced hours will change seasonally and there may be changes in long-term trends as well.[7]  

The design of the time-of-day multiplier should ensure storage DEB values are high enough during some hours to prevent inefficient dispatch under mitigation when opportunity costs are higher, while still protecting against potential exercise of market power during high-priced hours when opportunity costs are lower and market conditions may be tight. Intraday opportunity costs are higher leading up to the highest-priced hours and lower during these highest-priced hours. When prices are highest, the opportunity cost of being available in future hours is low as the highest prices have already materialized and there is time for the battery to recharge prior to the next set of high-priced hours. While DMM’s preliminary analysis focused on the highest prices of the evening peak, having high and low multiplier periods leading up to and during the evening peak, DMM supports the ISO’s illustrative proposal to include high and low multiplier periods based on the morning peak as well.

The current storage DEB formulation uses the N^th highest price of the day to estimate opportunity cost within the day.[8] Because this is a static value that does not account for multiple charging and discharging opportunities throughout the day, this value overstates the opportunity costs in many hours, and may underestimate the opportunity cost in others.

DMM recommends the storage DEB multiplier take on values both greater than and less than one to ensure that opportunity costs are not under- or over-estimated during particular hours of the day. DMM acknowledges the importance of protecting storage resources from being mitigated to DEB values that understate the opportunity cost and could lead to inefficient dispatch in the real-time. DMM agrees there may be instances when the N^th highest day-ahead price may be too low to protect against such occurrences and therefore supports a multiplier that takes on values larger than one in hours where the opportunity costs are highest. However, values less than one are also necessary in some hours to reflect that opportunity costs are lower than the N^th highest price during certain hours of the day, particularly in net peak hours when opportunity costs are lowest and the potential for market power may be higher.

DMM recommends the ISO incorporate the time-of-day multiplier into the day-ahead storage DEB as well.  It is unclear to DMM why the same multiplier cannot be applied to day-ahead storage DEBs and why the ISO instead proposes to use the upper-bound of the multiplier throughout the entire day. DMM supports aligning the storage DEB structure across the day-ahead and real-time markets to support convergence between the two markets.

Inclusion of the gas floor as an input into the storage DEB does not seem appropriate as it is not directly related to the marginal cost of battery resources

As stated previously, DMM has shown that the storage DEB performs well overall as an input to local market power mitigation and does not result in significant inefficient real-time dispatch caused by mitigation. While DMM believes there are improvements that can be made to allow the storage DEB to more accurately reflect real-time conditions and variable intraday opportunity costs, DMM does not see how inclusion of the gas floor addresses either of these issues.

The gas floor is a value used in the short-term component of the hydro DEB, and it is one of several inputs used to estimate real-time prices at the resource’s location.[9] The current storage DEB estimates the opportunity cost of storage by using the prices at that resource’s node from previous market runs. DMM argues that this approach more accurately reflects expected prices at that resource’s location in upcoming hours than gas prices. This is especially true if the storage DEB includes additional multipliers as proposed to better account for intraday opportunity cost, or if the storage DEB were to include a scaling approach to more directly account for differences between day-ahead and real-time prices. Therefore, DMM questions whether inclusion of the gas floor is necessary or appropriate. While gas prices and electricity prices may be correlated, it is likely that the prices from previous market runs with appropriate scalar adjustments where appropriate will reflect gas prices when applicable.

DMM does not see a theoretically justified reason for including the gas floor in the storage DEB, and requests the ISO provide further justification for why the gas floor should be included in an estimate of the marginal cost of a storage resource.

DMM supports non-generator resource (NGR) outage management and nonlinearity modeling improvements, but these are not substitutes for storage BCR design changes

As discussed in the ISO’s May 18 presentation and the Second Revised Straw Proposal on Outage Management Topic Group, the ISO is proposing to add new functionality to the Outage Management System (OMS) and to create a modeled solution to represent the nonlinearity of lithium-ion batteries.[10]^,[11] DMM continues to support both improvements to increase the efficiency and transparency of the CAISO system.[12]^,[13] However, DMM notes that such enhancements should not be viewed as a substitute for  comprehensive bid cost recovery (BCR) design enhancements for storage resources. 

The ISO’s May 18 presentation appears to suggest that other enhancements will be pursued before continuing work on storage BCR design, and that the ISO will “assess whether additional BCR changes are needed” after implementing such enhancements. DMM disagrees with this approach and recommends the ISO continue to prioritize BCR design for storage resources independent and ahead of other storage market design changes that may further delay work on storage BCR design.

DMM supports Master File changes and outage reporting processes that improve transparency 

In the ISO’s May 2025 Issue Paper and Straw Proposal on Outage Management, Nonlinearity, and SOC Clarification, the ISO proposed to introduce new outage card types and clarifications unique to storage resources. Related changes were also introduced into the Business Practice Manual (BPM) Change Management process. The ISO has since removed all of these proposed changes from both the market design proposal and the BPM Change Management process.

In comments on the May 2025 Issue Paper and Straw Proposal, DMM focused on the updates to new OMS outage types unique to storage resources, and clarifications to resource management in the BPM Change Management process. The focus of the comments was on outage type usage to avoid RAAIM, and improved transparency for distribution connected resources.[14],[15] As noted in these earlier comments, DMM continues to recommend the ISO increase transparency around distribution-level resources by creating a flag in Master File to facilitate monitoring of these resources. DMM also continues to support OMS enhancements where added transparency may be needed.

The proposed OMS enhancements outlined in the May 7 Second Revised Straw Proposal would allow for automated acceptance of an outage change request into the system following submission, and power minimum rerates on test energy cards during new resource implementation. DMM understands this will increase the efficiency of OMS for operations purposes. However, DMM finds the scope of improvements limited when a goal was to increase the transparency of storage resource outages. The Master File modeling of nonlinearities will reduce the need for some outages, but there are additional limitations experienced by storage resources that would benefit from additional outage card types to increase the transparency of their physical limitations.

One leading factor for storage resource outages (or derates) are power nonlinearities when the storage resource is near the minimum or maximum SOC. DMM continues to support the development of a Master File solution to approximate and incorporate the nonlinearities into the market model. The proposed solution to modeling nonlinearity uses additional Master File parameters that will scale the charging and discharging capabilities of the resource linearly with SOC in the extreme ranges of SOC. The solution creates an envelope for the operational range of storage resources to ensure feasible dispatches and allow for full access to the stored energy of the resource. DMM requests the ISO provide the mathematical formulation of the modeled approach, such as whether the envelope will be a hard constraint or have a penalty price.

Modeling nonlinearities through Master File will reduce the frequency of OMS use to reflect these limitations. However, there may still be cases when a storage resource will experience a power derate due to nonlinearities beyond the modeled approach that may need to be reflected to the market. Since these limitations will still exist and need to be included in the market through OMS, DMM continues to recommend the ISO create additional outage types specific to storage resource limitations.

Changes to storage resource modeling will impact other areas of the market

DMM has cautioned that any changes to storage capacity modeling, such as the Master File update for nonlinearities, need to contemplate the interrelated policies around resource adequacy and RAAIM. Any power output limitation on resource adequacy capacity, even if modeled in Master File, should be subject to RAAIM. The ISO has indicated that RAAIM will be addressed in the Resource Adequacy Program and Modeling Design (RAMPD) initiative. DMM will continue to be an active stakeholder in that process.

Further, DMM recommends the ISO clearly articulate how power limitations arising from this modeling approach will interact with interrelated market products, such as ancillary services, and the Day-Ahead Market Enhancement products of imbalance reserves and reliability capacity. The 24-hour optimization of day-ahead products should allow for more straightforward incorporation of modeled nonlinearities. However, the real-time products may run into limitations such as ancillary service deliverability. DMM recommends the ISO detail the interactions of the ancillary service SOC constraint and how changes in power limits from the new model will ensure real-time deliverability.

NGR bidding enhancements could improve storage modeling, but DMM recommends the ISO continue to prioritize BCR design for storage resources

In January 2026, the ISO presented a potential new non-generator resource (NGR) bidding model for storage resources that would allow the resources to bid state-of-charge, instead of power output.[16] The ISO introduced another alternative approach to a new NGR bidding model in the May 18, 2026 stakeholder meeting.[17]

The NGR bidding approach presented in May appears to be a simplification of the January proposal. As an initial point, DMM asks the ISO to clarify whether the May proposal is a replacement for the January proposal, an interim step, or a first step to developing a more complete biddable SOC model.

The NGR bidding proposal introduced in May would allow storage resources to bid a single-value end-of-horizon state-of-charge (EOH SOC) parameter. In the day-ahead, the EOH bid will provide a parameter for the market software to optimize storage schedules given the financial willingness of a resource to deviate between its initial and end-of-day SOC. This would indicate to the market the shadow value of the stored energy at the end of the day, which the current market model does not consider explicitly. In the real-time, the EOH bid will be a willingness to deviate from the day-ahead SOC trajectory, which similarly will allow the market to assign a value to the SOC outside of the optimization horizon.

DMM notes that in addition to the EOH SOC parameter, both the day-ahead and real-time model would also need to allow an intra-horizon bid parameter that reflects the minimum spread needed to cover variable O&M costs incurred by operating within the optimization horizon. This value would be reflected today in energy bids to charge and discharge. If such bids were eliminated in their current form, it is unclear from the May 18 presentation if such a parameter would be included.

DMM continues to view these types of enhancements as a significant improvement for storage resources in the NGR model, as it will allow them to better represent their costs and operational characteristics to the market.[18] However, the development and implementation of a new NGR bidding model for storage is a large undertaking that seems likely to require significant resources by the ISO and stakeholders. As noted earlier in these comments, DMM recommends the ISO continue to prioritize BCR design for storage resources ahead of other storage market design changes that may further delay work on storage BCR design. 

The NGR bidding concept does not address issues with the BCR design for storage resources

The ISO indicated in the presentation that this proposed improvement “mitigate[s] the risk of inefficient dispatch from incorrect bids/offers within the optimization horizon because misestimated costs/prices no longer distort market outcomes.” An EOH SOC opportunity value may mitigate inefficient dispatch by allowing the market model to optimize within the optimization horizon, accounting for the opportunity value of the SOC beyond the optimization horizon. However, it does not solve DMM’s core concern that the current BCR design doesn’t incentivize efficient real-time bidding. The EOH SOC value will still necessarily be determined by a forecast of real-time prices later in the day as storage energy bids are today, and the current BCR design does not incentivize resources to submit bids that reflect real-time conditions because the current BCR design for storage resources does not leave the resources exposed to real-time prices.[19]

DMM supports exploring SOC-based bidding, but emphasizes the need for clarity and consideration of market power mitigation impacts

In principle, DMM is supportive of an SOC-based bidding construct for storage resources, and requests the ISO to more generally elaborate on their intended direction with SOC bidding. Further, as SOC bidding functionality is explored, it will be important to consider market power mitigation in these frameworks. Unlike cost-based bids, the reference levels of SOC bids are not as readily observable and have the possibility of leading to new gaming strategies. As a result, SOC bidding frameworks will need to be jointly evaluated with future DEB enhancements.

[1]  Storage Design and Modeling: Working Group on Uplift and Default Energy Bids, and Outage Management presentation, California ISO, May 18, 2026: https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-Storage-Design-Modeling-May-18-2026.pdf

[2]  Ibid, slide 8.

[3] 2024 Special Report on Battery Storage, Department of Market Monitoring, May 28, 2025: https://www.caiso.com/documents/2024-special-report-on-battery-storage-may-29-2025.pdf

[4] Comments on Energy Storage and Distributed Energy Resources Storage Default Energy Bid Draft Final Proposal, Department of Market Monitoring, October 9, 2020: https://www.caiso.com/documents/dmmcomments-esder4storagedefaultenergybiddraftfinalproposal-oct92020.pdf

[5] Comments on Storage Design and Modeling Working Group Presentation on March 16, 2026, Department of Market Monitoring, April 3, 2026: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-mar-16-2026-working-group-presentation-apr-03-2026.pdf

[6] Comments on Storage Design and Modeling Working Group Presentation on March 16, 2026, Department of Market Monitoring, April 3, 2026, pp 10-11.: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-mar-16-2026-working-group-presentation-apr-03-2026.pdf

[7] Comments on Storage Design and Modeling Updated Discussion and Issue Paper on Uplift and Default Energy Bid, Department of Market Monitoring, January 8, 2026: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-updated-discussion-and-issue-paper-on-uplift-and-default-energy-bid-jan-8-2026.pdf

[8] The price-based opportunity cost will be set at the value of the highest price corresponding to the discharge duration of the resource; for example, if a storage resource has a four-hour discharge duration, the price-based opportunity cost will be the fourth-highest price. See Market Instruments BPM - Attachment D.

[9] Local Market Power Mitigation Enhancements Draft Final Proposal (Updated), California ISO, January 31, 2019: https://stakeholdercenter.caiso.com/InitiativeDocuments/DraftFinalProposal-LocalMarketPowerMitigationEnhancements-UpdatedJan31_2019.pdf

[10] Storage Design and Modeling: Working Group on Uplift and Default Energy Bids, and Outage Management         presentation, California ISO, May 18, 2026: https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-Storage-Design-Modeling-May-18-2026.pdf

[11]  Storage Design and Modeling: Second Revised Straw Proposal on Outage Management Topic Group, California ISO, May 7, 2026: https://stakeholdercenter.caiso.com/InitiativeDocuments/Second-Straw-Proposal-Outage-Management-Topic-Storage-Design-Modeling-May07-2026.pdf

[12]  Comments on Storage Design and Modeling Working Group Presentation on January 22, 2026, Department of Market Monitoring, February 17, 2026: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-jan-22-2026-working-group-presentation-feb-17-2026.pdf

[13]  Comments on Storage Design and Modeling Issue Paper and Straw Proposal on Outage Management, Nonlinearity, and SOC Clarification, Department of Market Monitoring, May 23, 2025: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-issue-paper-and-straw-proposal-on-outage-management-nonlinearity-and-soc-clarification-may-23-2025.pdf

[14]  Ibid.

[15]  Comments on Storage Design and Modeling Working Group Presentation on September 29, 2025, Department of Market Monitoring, October 14, 2025: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-sep-29-2025-working-group-presentation-oct-14-2025.pdf

[16]  Storage Design and Modeling: Working Group on Uplift & DEB, Outage Management, and State-of-Charge Management presentation, California ISO, January 22, 2026: https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-Storage-Design-Modeling-Jan-22-2026.pdf

[17] Storage Design and Modeling: Working Group on Uplift and Default Energy Bids, and Outage Management Presentation, California ISO, May 18, 2026: https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-Storage-Design-Modeling-May-18-2026.pdf

[18]  Comments on Storage Design and Modeling Working Group Presentation on January 22, 2026, Department of Market Monitoring, February 17, 2026: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-jan-22-2026-working-group-presentation-feb-17-2026.pdf

[19]  Comments on Storage Design and Modeling Working Group Presentation on January 22, 2026, Department of Market Monitoring, February 17, 2026: https://www.caiso.com/documents/dmm-comments-on-storage-design-and-modeling-jan-22-2026-working-group-presentation-feb-17-2026.pdf

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

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. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

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. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

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. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

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 provide any additional comments, feedback, or examples. You can upload supporting materials 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 a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

Energy Division staff (ED Staff or Staff) of the California Public Utilities Commission (CPUC) develops and administers energy policy and programs to serve the public interest, advises the CPUC, and ensures compliance with CPUC decisions and statutory mandates. ED staff provides objective and expert analyses that promote reliable, safe, and environmentally sound energy services at just and reasonable rates for the people of California. 

Staff supports the CAISO proposal to reflect non-linearity in the market model. The issue of non-linearity, or foldback, is a significant issue in the CPUC’s Resource Adequacy (RA) reform to develop an Unforced Capacity (UCAP) framework. Many parties in the CPUC proceeding advocate not including capacity reduction due to non-linearity as a forced outage which impacts the resource’s UCAP calculation. In addition, several parties commented that a battery storage resource that meets the four-hour continuous discharge rate requirement, per the CPUC rules for qualifying capacity, but in the fifth hour reduces its capacity due to non-linearity would have that outage included as a forced outage and would reduce its UCAP value. The problem is non-linearity outages are reported as plant trouble so there is no way to exclude, if necessary, these outages.  

Staff recommends that the CAISO add an outage code that reflects the non-linearity issue.  In addition, CAISO should consider whether other types of outage codes are needed for wind, solar, and storage resources.     

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

During the working group meeting, CAISO proposed a “time-of-day" default energy bid (DEB) concept that aims to address:

• Reliance on outputs from prior market runs or “stale” data (i.e. using day-ahead LMPs for the real-time DEB)
• Static values that fail to reflect changing intraday opportunity costs
• Inability for WEIM-only resources to leverage the DEB since they do not participate in the DA market

The new framework proposes to: 

• Eliminate energy costs from the current calculation  
• Introduce a gas floor to capture opportunity cost and ensure correct placement of storage within the bid stack, similar to the hydro DEB framework 
• Scale price proxies to address stale values 
• Introduce a shaping multiplier that varies throughout the day (between 0.6-1.4) to show willingness to charge/discharge 

Staff would like to better understand the methodology and justification for determining the shaping factor multipliers, and how the CAISO will avoid forced uneconomic discharge. Staff also requests clarification on how these values will accurately reflect seasonal changes and differences throughout the year. ED Staff is concerned about DEBs that are too high or too low relative to the opportunity cost of that hour, and the resulting unintended outcomes that may lead to unwarranted uplift costs which are passed on to ratepayers. This is especially high priority in light of recent changes in system-wide offer caps in the changing market landscape. 

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

No comments at this time. 

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

No comments at this time.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

In the interim while a modeled solution is implemented, Staff supports CAISO’s recommendation that market participants should manage risk of infeasible dispatch instructions by only reflecting the state of charge (SOC) range unaffected by foldback in the master file. Staff also agrees that if a resource cannot deliver due to foldback they should be subject to RAAIM penalties, since it is considered a known operational limitation.  

Staff supports the CAISO’s proposal to reflect non-linearity in the market model. However, Staff disagrees that it has been clearly demonstrated that outage cards related to non-linearity are no longer needed. The market model is a representation of the SOC of the battery system. If the operator estimate of its state of charge is not a good representation of actual conditions, or if other system conditions are driving the system into non-linearity that was not modeled, an outage card for non-linearity may still be needed. Improved reporting of the nature of outages will also help parties understand the reliability of resources. Staff recommends that an outage card for this non-linearity issue be added to the reporting system. 

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) appreciates the opportunity to comment on the California Independent System Operator Corporation’s (CAISO) May 18, 2026 meeting on CAISO’s Storage Design and Modeling Initiative (Workshop)[1] and the May 7, 2026 Second Revised Straw Proposal on Outage Management Topic (Second Revised Straw Proposal).[2]

Cal Advocates provides the following comments on the May 18 Workshop and the Second Revised Straw Proposal:

• CAISO should consider whether the use of a gas peaker as the proxy “gas floor” resource is appropriate and sufficient to ensure that storage maintains its position in the bid stack when mitigated without unduly inflating the storage default energy bid (DEB).
• CAISO should consider whether it is appropriate to include the gas floor term in all hours, rather than in the subset of hours in which gas or other selected proxy resources are most likely to be operating on the margin.  Storage should be able to maintain its position in the bid stack without unduly inflating the DEB in hours when gas is not on the margin.
• CAISO should conduct a study to select the most appropriate multiplier for the opportunity cost input to the hydro-based day-ahead (DA) DEB calculation for storage.  CAISO conducted a specific study for hydro resources to ensure that the multiplier does not unduly inflate the storage DA DEB.  If CAISO uses this multiplier for storage, CAISO should replicate the hydro study for storage resources.
• CAISO should perform a detailed assessment of the impact on resource adequacy (RA) capacity resulting from modifications in Master File parameters for non-linearity.  CAISO should use the study to provide assurance that any changes will not adversely impact the availability of RA capacity, degrade system reliability, or increase ratepayer costs.
• CAISO should provide a more specific timeline with milestones for its non-linearity market model implementation.

[1] CAISO, Storage Design and Modeling Working Group on Uplift & Default Energy Bids and Outage Management, May 18, 2026 (Workshop Slides).  Available as “Presentation - Storage Design and Modeling – May 18, 2026” at: https://stakeholdercenter.caiso.com/StakeholderInitiatives/Storage-design-modeling.

[2] CAISO, Storage Design and Modeling Second Revised Straw Proposal on Outage Management Topic Group, May 7, 2026.  Available as “Second Revised Straw Proposal on Outage Management Topic Group – May 7, 2026,” at: https://stakeholdercenter.caiso.com/StakeholderInitiatives/Storage-design-modeling.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

CAISO proposes to develop a varying hourly time-of-day (TOD) DEB for energy storage.  CAISO would calculate separate DEBs for the DA and real-time (RT) markets based upon existing market information.[1]  CAISO proposes that the final DEB design should: 1) allow for changing RT storage opportunity costs to maintain the correct position of storage in the bid stack; 2) provide DEBs for resources in the Extended Day Ahead Market (EDAM) regions as well as the Western Energy Imbalance Market (WEIM), and 3) minimize charging-side mitigation.[2]  Cal Advocates supports this set of design principles.

CAISO currently calculates a static DEB for the RT market based upon an opportunity cost represented by the nth highest DA Locational Marginal Price (LMP), where n is the duration of a given storage resource in hours.  CAISO states that a static RT DEB has the potential to over- or under-estimate opportunity costs at different hours of the day.[3]  In prior comments, Cal Advocates noted that, as a general matter, storage has a near-zero opportunity cost in the peak load hours because, if CAISO does not dispatch the resource in those hours, the resource will lose revenue in those hours and gain the opportunity to earn revenue in the remaining, lower-priced hours of the day.[4]  Conversely, storage opportunity costs are high before the peak hours because, if CAISO issues an early dispatch instruction, the storage resource loses the opportunity to dispatch later at higher prices.  As such, the final RT DEB calculation should reflect low opportunity costs in high load, high priced hours, and high opportunity costs in hours before the peak.

CAISO calculates the current storage static RT DEB as the maximum of: 1) the DA energy cost plus variable operations cost, or 2) the DA opportunity cost.  The DA energy cost is the average energy price over the lowest priced n hours, plus the fraction of hours that cover the round-trip efficiency loss of the resource.  The DA opportunity cost is set to the nth highest DA price.[5]

CAISO proposes to replace the current storage RT DEB calculation with a variation of the DEB calculation that CAISO uses for hydro resources, multiplied by an hourly shaping factor to produce the final RT TOD DEBs.[6]  Compared with the current DEB formula, the hydro-based DEB calculation removes the DA energy cost component and adds a “gas floor” term to the maximization function.  The gas floor represents the variable fuel-based cost of a natural gas peaker to ensure that gas resources are not dispatched before storage if the storage is mitigated to its DEB in the local market power mitigation process (LMPM).  The modification provides assurance that storage resources will maintain their position in the bid stack, if mitigated.  Cal Advocates supports this general modification as a reasonable method to minimize distortions in resource dispatch due to LMPM.  However, CAISO should consider whether the use of a gas peaker as the proxy gas floor resource is the most representative marginal resource to ensure that storage can maintain its position in the bid stack without unduly inflating the DEB.  For example, CAISO should consider the use of a more efficient combined-cycle plant as the proxy resource, which would result in a lower DEB floor.  Moreover, CAISO should consider whether it is appropriate to include the gas floor term in all hours, rather than in the subset of hours in which gas resources are most likely to be marginal.

CAISO’s final step to calculate the hourly RT TOD DEB to applies hourly shaping factors to reflect the expectation of varying RT energy prices and opportunity costs.[7]  This step is intended to accurately capture historical patterns of high mid-day opportunity costs and low peak-period opportunity costs in the RT TOD DEB.[8]  Consequently, it is appropriate that CAISO use shaping factors that vary from less than 1.0 to greater than 1.0 to reflect lower or higher hourly RT opportunity costs relative to the static DA opportunity cost.  The TOD peak-hour RT DEBs should be less than the static DA opportunity cost, while the TOD mid-day RT DEB should be higher than the DA static opportunity cost, and at a “floor” that is just sufficient to ensure that storage resources maintain their position in the bid stack if mitigated in the LMPM, as captured by the gas floor term in the formula.

CAISO also proposes to apply a variation of the DA hydro DEB formula for the DA storage DEB calculation.[9]  The DA hydro formula is the same as the RT DEB formula, except that the formula includes a 1.1 multiplier for the variable cost and the gas floor components and a 1.4 multiplier for the opportunity cost component.[10]  The multiplication factors represent a “margin of error” between the information available to CAISO when the DEB is calculated and the actual incremental costs facing generators.[11]  CAISO states that the 1.1 multiplication factor is “consistent with other DEB calculations” to cover uncertainty.[12]  However, CAISO developed the 1.4 multiplication factor for opportunity costs empirically for hydro resources by calculating the DEB for each day without a scalar and comparing it to RT fifteen minute market prices in the resource’s balancing area over a year.[13]  CAISO states that a larger multiplier would account for a greater range of potential outcomes, but could also inflate costs unnecessarily.[14]  Hydro resources that optimize their stored energy over weeks or months face a significantly different optimization problem than batteries that optimize over hours to days.  CAISO should conduct a similar study for storage resources to ensure the multiplier does not unnecessarily inflate the DA DEB for storage.

[1] Workshop Slides at 23.

[2] Workshop Slides at 18.

[3] Workshop Slides at 17.

[4] Cal Advocates, Comments on the March 16, 2026 Storage Design Workshop, April 3, 2026 at Response to Question 3.  Available at: https://stakeholdercenter.caiso.com/Comments/AllComments/27b1cda3-70c2-4575-864a-1cc229a40fd4#org-980d0933-87c6-460f-a1ad-7c9fc59dbb91.

[5] Workshop Slides at 12.

[6] Workshop Slides at 27.

[7] Workshop Slides at 26.

[8] Workshop Slides at 26.

[9] Workshop Slides at 23.

[10] Workshop Slides at 23.

[11] CAISO, Rules for Bidding Above the Soft Offer Cap, Final Proposal, May 17, 2024 (Bid Cap Final Proposal) at 26.  Available as “Final Proposal - Price Formation Enhancements” at: https://stakeholdercenter-stage.caiso.com/StakeholderInitiatives/Price-formation-enhancements.

[12] Bid Cap Final Proposal at 25-26.

[13] Bid Cap Final Proposal at 27.

[14] Bid Cost Final Proposal at 27.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

CAISO presented a concept to modify the current RT end-of-hour (EOH) state-of-charge (SOC) parameter.[1]  Storage operators currently have the option to submit an EOH target SOC range to directly manage SOC throughout the operating day.[2]  CAISO issues dispatch instructions to charge and discharge the resource to meet the SOC range, with precedence given to the target range over the resource’s energy bids.  Consequently, CAISO may issue uneconomic dispatches if the energy bid does not guide dispatch.  The EOH SOC bid is an optional, operator selected parameter, and thus the resource is not eligible for bid cost recovery (BCR).[3] 

CAISO’s EOH SOC concept, proposed in response to a 2020 opinion from the Market Surveillance Committee (MSC), is to add a $/megawatt-hour (MWh) parameter to the EOH SOC bid to value deviations from the target range within the market optimization.[4] With the new parameter, the optimization will put a bid-defined value on stored energy beyond the end of the optimization horizon.  By explicitly valuing storage energy, the addition of the $/MWh value parameter for EOH SOC may yield more efficient and economic storage dispatches and market results.  CAISO should continue to develop this concept as part of a broader, long-term and fundamental reform of BCR, DEBs and the non-generator resource (NRG) participation model for storage.  However, CAISO should maintain its policy that resources that submit self-selected parameters, including EOH SOC bids with $/MWh deviation values, are ineligible for BCR to prevent strategic bidding to increase uplift revenues.

[1] Workshop Slides at 30.

[2] CAISO, Storage Design and Modeling Uplift and Default Energy Bid Working Group Updated Discussion and Issue Paper, December 12, 2025 (Updated Issue Paper) at 47.  Available as “Discussion and Issue Paper - Storage Design and Modeling - Uplift and Default Energy Bid - Dec 12, 2025” at: https://stakeholdercenter.caiso.com/StakeholderInitiatives/Storage-design-modeling.

[3] Updated Issue Paper at 47. 

[4] Workshop Slides at 30.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

Cal Advocates does not have comments at this time.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

Cal Advocates supports CAISO’s proposal to implement a market model for non-linearity.[1]  CAISO proposes to implement the model “no-sooner-than spring 2027,”[2] and until then, CAISO proposes that storage operators choose one of two options to manage non-linearity.[3]   

The first option for operators is to submit maximum and minimum megawatt (MW) values to the Master File that exclude the storage non-linearity region.  Under this option, CAISO would not access storage capacity in the non-linearity region.  Consequently, storage operators would not be subject to Resource Adequacy Incentive Mechanism (RAAIM) penalties associated with non-linearity caused outages. 

The second option for operators is to submit minimum and maximum MW values that include part or all the non-linearity region.  Under this option, CAISO would dispatch the storage resources into the non-linearity regions when needed, and the resources could be subject to RAAIM penalties if they submit a non-linearity caused outage.

CAISO’s proposal is reasonable because it provides storage owners with a choice of options that best suits their specific operations and contractual provisions.  Moreover, CAISO previously indicated that most storage resources already restrict the non-linearity range in the Master File,[4] presumably in part to minimize RAAIM penalties, as well as to mitigate deep discharges that degrade battery life.  As such, CAISO’s proposal will likely not materially impact the RA capacity available from storage resources, while continuing to provide operators with the option that best suits their situation.  However, in prior comments, Cal Advocates requested that CAISO perform a detailed assessment of the impact on RA capacity resulting from modifications in Master File parameters for non-linearity.[5]  Cal Advocates reiterates that CAISO should perform such a study to provide assurance that its proposals will not adversely impact the availability of RA capacity, degrade system reliability, or increase ratepayer costs.  CAISO should also provide a more specific timeline with milestones for its non-linearity market model implementation.

[1] Workshop Slides at 53.

[2] Workshop Slides at 55.

[3] Workshop Slides at 66.

[4] CAISO, Storage Design and Modeling Working Group on Outage Management, Uplift & DEB, and Mixed-Fuel & Distribution-Level Resources, November 12, 2025 at 17.  Available as “Presentation - Storage Design and Modeling - Nov 12, 2025” at: https://stakeholdercenter.caiso.com/StakeholderInitiatives/Storage-design-modeling.

[5] Cal Advocates, Comments on Nov 12 Hybrid Meeting, Working Group Session 10: Uplift and Default Energy Bids (DEB), State-of-Charge Management, and Mixed-Fuel and Distribution-Level Resources, November 26, 2025 at Response to Question 3, Available at: https://stakeholdercenter.caiso.com/Comments/AllComments/7ebde4c4-2e11-413b-a307-d130a5313c5c#org-2f64b51e-9ed3-469d-a83b-93bdc4ee4075.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

Cal Advocates does not have additional comments at this time.

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

NV Energy appreciates CAISO’s continued commitment to developing a Storage Default Energy Bid available to WEIM-only resources.  NV Energy also appreciates CAISO considering stakeholder feedback and incorporating a gas-floor component similar to the Storage Hydro DEB.  As mentioned in previous comments and acknowledged by CAISO Staff, NV Energy believes that adding a gas-floor component ensures that a storage resource is preserved in the correct position in the bid stack, even under mitigation.

NV Energy still seeks clarification regarding the time-of-day (TOD) component and whether it’s necessary to calculate a Storage RT DEB. This stakeholder initiative should take a moment to pause and determine if the level of precision is necessary to accurately depict a RT DEB curve because it adds a level of complexity that may not be needed which ultimately adds to the Grid Management Charge.  CAISO should begin evaluating the costs of implementation during the stakeholder initiative phase so that stakeholders can see if the value of a very precise tool is worth the cost.

Nevertheless, if this initiative moves forward with a RT DEB curve, then NV Energy requests clarification on how the multiplier and the scaler are calculated, when they are calculated, and whether and when they will be made available to stakeholders.  During the stakeholder call, CAISO staff and stakeholders suggested several time frame options for updating the TOD multiplier and scaler such as seasonal, quarterly, or annual updates.  NV Energy suggests that any temporal time frame selected should reflect Real-Time conditions as close as possible and should be determined based off analysis. Whichever temporal time frame is selected, NV Energy stresses that these decisions and data are made available to stakeholders in a timely manner to ensure transparency. 

Furthermore, NV Energy suggests that if a TOD Multiplier is adopted, the value should be greater than or equal to 1.0.  A TOD multiplier less than 1.0 counter acts the effort to ensure that an accurate DEB is used and the storage resource is placed correctly in the bid stack.    

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

PG&E appreciates several proposed improvements in the storage design and modeling initiative, but remains cautious at this stage because important design details, implementation issues, and potential impacts require further clarification.

• PG&E remains neutral on the storage DEB enhancements at this stage. While the proposal incorporates several changes consistent with PG&E’s prior comments, additional clarity is still needed on multiplier design, implementation details, and potential incentive effects. If the ISO moves forward, PG&E recommends make-whole treatment for uneconomic charging and time-of-day multipliers at or above 1.0.
• PG&E would like to see additional detail in developing the MSC’s NGR bidding concept  and encourages inclusion of intra-horizon constraints, price formation, make-whole needs, interactions with other products, and incentive effects in the next iteration of the idea.
• PG&E agrees that the current outage reporting framework should better account for overlapping battery constraints. PG&E requests further work on a more unified outage reporting approach for battery resources and asks CAISO to clarify how these enhancements may affect RA performance and qualifying capacity assumptions.
• Changes to storage modeling may affect qualifying capacity, compliance, and contractual obligations. PG&E recommends additional details on dispatch treatment, ancillary-service-related constraints, and battery derates, along with explicit evaluation of RA and contractual impacts before the proposal advances further.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

PG&E remains neutral on the ISO’s proposed Storage Default Energy Bid (DEB/DAB) enhancements at this stage.

PG&E appreciates the ISO’s effort to modernize the framework and acknowledges that a dynamic, time-dependent approach may improve upon the current static formulation, which can become stale and less reflective of changing system conditions. PG&E also recognizes that the proposal incorporates several changes consistent with PG&E’s prior comments, including removal of explicit consideration of charging costs, clarification that charging is not subject to mitigation, inclusion of a gas price floor as a minimum value in the DEB calculation to help ensure storage is properly positioned in the bid stack, and defining the primary term of the calculation as a Price-Based Opportunity Cost (PB_OC).

PG&E nevertheless remains neutral because key design details are still unresolved and the proposal may create incentive risks depending on how it is implemented. In particular, market participants may respond strategically to known bid structures, including by shifting participation between the day-ahead and real-time markets or relying more heavily on default bids under certain conditions. Additional clarity is needed on the methodology for setting time-dependent multipliers, the look-ahead horizon and sensitivity of those multipliers to forecast conditions, and how the framework performs when real-time conditions diverge from day-ahead expectations. PG&E recommends that these issues be addressed in the next straw proposal to support further evaluation.

PG&E offers the following technical recommendations:

• To address situations where storage resources are required to charge uneconomically, PG&E recommends that such resources automatically receive a make-whole payment based on the Default Energy Bid (DEB) discharge value rather than the charging bid. Charging bids could otherwise be strategically manipulated, and uneconomic charging can arise from imbalance reserve and ancillary service awards in the day-ahead market, as well as reliability-driven dispatch instructions in real-time (e.g., advisory dispatch constraints). Basing compensation on the DEB discharge value ensures payments reflect the underlying economic value of stored energy while mitigating incentives for strategic bid inflation.
• PG&E further recommends that all time-of-day (TOD) multipliers be set at or above 1.0 to ensure that storage resources are not required to bid to discharge at prices below their expected marginal discharge value prior to net peak hours. Multipliers below 1.0 could force batteries to understate the value of stored energy based on average expectations that may not hold in actual market conditions. In practice, intervals with elevated charging costs—such as mid-day periods—can result in realized opportunity costs that exceed expected values. Therefore, the DEB design should account not only for expected outcomes but also for the variability observed in real-world market conditions to avoid inefficient dispatch and distorted price signals.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

PG&E supports exploration of the NGR bidding concept put forth by the MSC. PG&E agrees that the current hourly monotonic bidding structure is overly restrictive and may not adequately reflect the intertemporal opportunity costs faced by storage resources. Movement toward a framework that better captures these dynamics is directionally appropriate.

However, PG&E is concerned that a single end-of-horizon value may be too simplified to fully reflect how storage resources operate in the market. Aside from questions regarding how intermediate constraints could be incorporated without enabling hourly bid curves — although optional use of hourly bid curves may be one possible approach — PG&E believes several concerns with the concept in its pure form should be considered.

1. Hourly reserve and ancillary service bids already create hourly energy values. Even if the proposal seeks to avoid hourly energy bid curves, hourly bids for imbalance reserves and ancillary services effectively imply interval-specific opportunity costs. As a result, the market may still produce hour-specific energy values indirectly, and the proposal may not fully eliminate hourly valuation concerns.
2. Make-whole payments may be required for uneconomic battery dispatch. If the market dispatches a battery in a manner that is not economically rational over the scheduling horizon, the resource may incur losses. A model based solely on an end-of-horizon value could still produce outcomes that are mathematically consistent, while failing to reflect actual charging costs or a no-loss condition. Accordingly, make-whole compensation may be necessary to address such uneconomic outcomes.
3. A single end-of-horizon value may not adequately capture intra-horizon constraints and dynamics. Storage resources are subject to both operational constraints (e.g., throughput limits, SOC limits) and time-varying opportunity costs driven by evolving market conditions such as renewable uncertainty and ancillary service requirements. Under the current framework, these effects can be reflected through variation in bids across the scheduling horizon. A purely end-of-horizon valuation may not represent these physical and economic dynamics effectively. As a result, important constraints may need to be specified explicitly (e.g., through master file or use plan parameters), and the interaction between such constraints and the deviation bid construct requires further consideration to ensure dispatch outcomes remain consistent with underlying system and resource conditions.

Separately, PG&E notes a broader market design consideration regarding the use of deviation bids. Reliance on a deviation bid introduces new avenues for strategic behavior and raises implications for market monitoring and mitigation. Under this framework, scheduling coordinators must submit a deviation bid representing the forward-looking marginal value of stored energy beyond the scheduling horizon. While forward-looking valuation is not new, its increased importance in determining dispatch outcomes introduces new challenges. Although the removal of multi-interval energy bids may reduce opportunities for traditional hourly bid-based manipulation, the deviation bid becomes the primary driver of charge and discharge decisions. This creates the potential for resources to influence dispatch outcomes through how future value is represented. For example, a resource may overstate its expected future energy value in order to avoid economically efficient discharge and retain state of charge, resulting in a form of strategic withholding. While this differs from traditional interval-level bid inflation, it may produce similar market impacts and could be more difficult to detect and mitigate. More broadly, this shift raises questions for the design of mitigation measures and market monitoring under the proposed framework. PG&E also notes that the interaction between this design and other market products, particularly Imbalance Reserves, requires further evaluation. In addition, the proposal may shift incentives in ways that alter participation between the day-ahead and real-time markets or affect the availability and value of other market products.

Finally, PG&E believes additional analysis is needed to understand how the proposed framework would affect market outcomes, including dispatch efficiency and price formation. It is important that price formation be explicitly described in the next iteration of the proposal, and that any requirements for make-whole payments be clearly specified.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

PG&E supports CAISO’s expediting the OMS enhancements identified as feasible and appreciates the clarity provided on their scope.

At a high level, PG&E agrees that the current outage reporting framework does not adequately capture overlapping constraints for battery resources and that this issue warrants further attention. PG&E supports the comment made by Vistra that the overlapping outage issue should be addressed, and suggests that a clearer understanding among stakeholders of why such overlap is currently not feasible could help identify more effective and collaborative solutions. As an example, many battery outages simultaneously affect multiple operating limits—such as maximum discharge, maximum charge, ancillary service capability, and SOC limits—which are often all driven by a single underlying factor like the number of available cells. In these cases, representing these related impacts through a single, unified outage card may better reflect the physical reality of the resource and could potentially allow coexistence with other outage types, such as clearance or ambient derates. PG&E also encourages the ISO to clarify how outage reporting enhancements may interact with RA performance and qualifying capacity assumptions where overlapping battery constraints materially affect deliverability.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

PG&E supports efforts to improve operational frameworks for storage resources, including enhancements to outage management and modeling approaches. However, PG&E is concerned that the current proposal does not sufficiently evaluate impacts to Resource Adequacy (RA). In particular, changes to storage modeling—such as derates or revised operational assumptions—may reduce the effective qualifying capacity of resources and create misalignment with existing contractual obligations, including contracted MW amounts. These impacts could introduce material financial and compliance risks for load-serving entities and resource owners. PG&E therefore recommends that the next iteration provide greater clarity on key implementation details and explicitly evaluate RA and contractual impacts within this initiative. In particular, PG&E requests additional detail on real-time dispatch, the treatment of ancillary service-related constraints in both the day-ahead and real-time markets, and how constraints associated with battery derates (e.g., based on the number of available cells) will be represented.

PG&E further recommends that more restrictive foldback constraints be reportable in OMS, particularly in cases where operational limits differ from master file values (e.g., where master file limits allow operation down to 5% SOC, but foldback effectively constrains operation at 10%). Allowing such reporting would better align outage representation with actual resource capability.

However, PG&E notes that constraints which reduce effective dispatch capability and limit RA deliverability may result in RAAIM-related penalties (or their future equivalent). For that reason, the interaction between these reported constraints, RA performance obligations, qualifying capacity, compliance requirements, and contractual commitments should be clearly defined before the proposal advances further.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

PGE appreciates the ISO’s ongoing engagement with stakeholders and supports near-term outage management enhancements that improve the ability of storage resources to communicate availability and operational limitations. PGE supports the ISO’s prioritization of OMS improvements such as allowing most outage change requests to be reflected immediately after submission and enabling power minimum rerates on test energy cards during new resource implementation. These enhancements should improve data timeliness, reduce manual burdens, and better support accurate communication of storage availability.

At the same time, PGE encourages the ISO to treat outage enhancements as interim tools rather than a substitute for durable model-based solutions. Storage limitations tied to state of charge, foldback, or other operating characteristics may not be well represented through outage cards designed for static derates or equipment outages. PGE therefore supports continued development of modeled storage solutions, including Master File/GRDT parameters and associated market constraints, and requests continued clarity on how outage cards should be used before and after those solutions are implemented.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

PGE supports the ISO’s efforts to enhance storage Default Energy Bid (DEB) framework and recognizes the importance of better reflecting storage resources’ time-varying opportunity costs,  limited duration, and state-of-charge considerations. Improvements to storage DEBs can help support more accurate mitigation outcomes and reduce the risk that mitigated bids do not reflect the actual value of storage availability.

However, PGE encourages the ISO to coordinate DEB enhancements with related improvements to state-of-charge representation, dispatch feasibility, and modeling of storage operating limitations. DEB changes alone may no achieve the intended outcomes if the market model does not accurately reflect the resource’s physical capability to charge, discharge, or preserve state-of-charge across market intervals. PGE therefore supports continued development of storage DEB enhancements as part of an integrated storage framework that improves both mitigation accuracy and feasible market outcomes. Furthermore, CAISO should consider EDAM DA and RT market conditions, as market deviation during scarcity pricing events can lead to temporal constraints of the region's most flexible resources if mitigation is not prudent.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

PGE appreciates the Market Surveillance Committee’s continued evaluation of potential NGR bidding enhancements and supports further discussion of whether changes to the existing NGR bidding framework could improve storage participation in the ISO markets. As storage resources become increasingly important to reliability and market operations, bidding rules should provide sufficient flexibility for storage resources to reflect their operational constraints, state-of-charge needs, and time-varying opportunity costs. However, PGE encourages the ISO to ensure that any NGR bidding changes remain closely aligned with improvements to underlying storage modeling and operational clarity. Bidding enhancements alone may not resolve challenges that arise when the market model lacks  accurate state-of-charge information, does not fully reflect dispatch feasibility, or cannot account for physical limitations such as foldback/nonlinearity. PGE therefore supports continued exploration of NGR bidding changes as part of an integrated framework that improves both market flexibility and feasible dispatch outcomes.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

PGE supports the Outage Reporting Enhancements outlined in the second revised straw proposal and appreciates the ISO’s prioritization of improvements that increase OMS responsiveness, reduce manual burdens, and better reflect storage resource availability. PGE supports the planned enhancements to allow most outage change requests to be reflected in OMS immediately after submission and to allow power minimum rerates on test energy cards during new resource implementation.

PGE also continues to recommend that aggregate capability constraints be evaluated as allowable OMS parameters or through another appropriate market systems mechanism for aggregated and co-located resources. For these resources, managing point-of-interconnection constraints is currently limited to GRDT changes, which may not provide sufficient operational flexibility or transparency. Allowing aggregate capability constraints to be reflected through OMS. GRDT, Master File, or another appropriate mechanism would better support accurate outage and availability reporting for resources with shared interconnection or co-located configurations.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

PGE agrees that nonlinearity is a current modeling gap for storage resources and supports the ISO’s focus on improving its representation in the market model. PGE supports development of a modeled solution that uses resource-specific parameters and associated constraints to better reflect how charging and discharging capability changes near state-of-charge limits.

PGE remains concerned that relying on outage mechanisms to represent nonlinearity should be treated only as an interim approach. Managing nonlinearity through outage cards can create incremental operational burden and may not fully reflect the dynamic nature of storage limitations. PGE therefore encourages the ISO to pair near-term OMS guidance with longer-term Master File and GRDT enhancements, in addition to OMS enhancements, so storage limitations can be represented more accurately and with less manual intervention by operations staff.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

PGE appreciates the ISO’s continued efforts to address storage operational challenges and supports near-term enhancements that improve outage management, data timeliness, and operational visibility. However, PGE encourages the ISO to reconsider whether aggregate capability constraints should be accelerated or otherwise addressed through outage management enhancements, Master File/GRDT improvements, or another appropriate mechanism, particularly for co-located and hybrid resources.

Aggregate capability constraints should be treated as dynamic, manageable parameters that can provide the market with better visibility into real-time charging limitations, shared interconnection constraints, and interactions among jointly sited resources. While near-term OMS enhancements can improve operability, durable improvements will depend on continued progress toward model-based representation of state of charge, nonlinearity, and hybrid/co-located resource constraints.

PGE encourages the ISO to continue coordinating these issues across the Storage Design and Modeling workstreams so that operational tools, bidding rules, and market constraints evolve together.

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

REV Renewables (REV) appreciates CAISO’s proposals presented, and in particular is very supportive of the nonlinearity representation included in the Master File. REV offers additional feedback on the proposals below.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

REV appreciates the new concept and the direction of the storage DEB, but has several questions and details that REV requests are addressed in the next iteration.

• REV supports the concept of the gas floor to appropriately place storage resources in the bid stack. However, gas prices can also fluctuate each day especially as tight system conditions emerge. It is currently unclear in CAISO’s proposal where the 11,068MMBTu/MWh is from, how often this price would be updated, and which different fuel regions would be used. It would be helpful to have a gas price index that is more reflective of real time conditions.
• For the TOD scalar and multiplier approach, more information needs to be provided on how these numbers are determined and the rationale behind the methodology, as well as how often the multipliers would be updated. Updates monthly or seasonally at minimum would be necessary to reflect regular market shifts, though more frequent updates to reflect real-time conditions would be helpful particularly during scarcity conditions.
• Would this DEB apply to discharge only or also to charging?
• It would be helpful to see simulated market examples to see the impact of this new DEB on dispatch, and ensuring that it does not have unintended consequences of dispatching in off-peak periods.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

REV views this proposal as a lower priority item, but is open to discussing a new NGR bidding concept so long as the current bidding options remain in place. For those resources that do not use end-of-hour state-of-charge (EOH SOC) targets, this proposed concept introduces significant complexity and questions. If this bidding concept is in addition to the existing bidding structure, that would be helpful to clarify. In general, more examples and data would help provide clarity on how CAISO envisions this would work.

It would help to clarify whether this concept would be in real-time (RT) only, or also in day-ahead (DA). If a resource is awarded energy in the DA, what is the expectation on how to submit SOC bids in RT to maintain the ability to follow the awarded DA energy (MW, not MWh) schedule in RT? Would any mitigation of said SOC bids in RT consider the resource's telemetered SOC, taking into account that SOC expectations from DA would likely vary once in RT? If so, could CAISO clarify on how it is modelling or measuring SOC in RT?

If this could be only a bid to reach a certain end of day SOC that could be helpful to meet the next day initial SOC.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

REV has no comments at this time

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

REV supports CAISO’s proposal and thanks CAISO for its collaboration on this effort. REV encourages CAISO to include this in the Master File as soon as possible, and by Spring 2027 at latest.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

Southern California Edison (SCE) appreciates the opportunity to provide comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management. SCE’s comments can be summarized as follows: 

Storage Default Energy Bid (DEB) Enhancements 
SCE supports CAISO’s efforts to enhance the storage default energy bid framework to better reflect opportunity costs and operational realities, including the incorporation of price-based opportunity costs and scaling mechanisms. However, SCE emphasizes the need for greater transparency in the development of scaling factors and recommends that CAISO provide detailed methodologies, supporting data, and illustrative examples. SCE also recommends evaluating the interaction between DEB enhancements and recent bid cost recovery (BCR) changes to better understand potential impacts on uplift outcomes. 

End-of-Horizon (EOH) Bidding Concept 
SCE finds the Market Surveillance Committee’s proposed end-of-horizon bidding concept to be valuable but not yet sufficiently developed. SCE requests further clarification on the interaction with ancillary services, the role of the EOH parameter in scheduling versus pricing, and the overall impact on bidding complexity. SCE recommends that CAISO provide detailed examples demonstrating the application of this framework under realistic market conditions and consider extending similar concepts to the Day-Ahead market to better manage state-of-charge across time horizons. 

Outage Reporting Enhancements 
SCE supports the proposed outage reporting enhancements, including increased flexibility and improved representation of resource capabilities. SCE recommends incorporating prioritization logic for outage change requests to improve processing efficiency and reduce potential backlogs in both Day-Ahead and Real-Time markets. 

Representation of Storage Nonlinearity 
SCE supports CAISO’s proposal to enhance the modeling of storage nonlinearity through additional parameters capturing nonlinear operating characteristics. These enhancements will improve the accuracy of resource representation and support more efficient market outcomes. 

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

SCE supports CAISO’s effort to evolve the default energy bid (DEB) framework for storage resources to better reflect opportunity costs and operational realities.  The proposed shift toward incorporating price-based opportunity costs using scaling mechanisms represents a meaningful advancement over the current construct; however, SCE believes that key elements of the proposal require further development and transparency.  

SCE’s primary concern relates to the lack of transparency in the derivation of the scaling factors for those price-based opportunity costs. Without a documented methodology, it is difficult to assess whether these adjustments will produce consistent and predictable outcomes across a broad set of market conditions. SCE recommends that CAISO provide detailed formulas, supporting data, and illustrative examples demonstrating the calculation of the scaling factors.  When determining the methodology for scaling, CAISO should use data that is no more than a couple days old to calculate the scaling factor. This should help account for seasonal changes and heatwaves. 

SCE also supports the inclusion of gas price floors and time-of-day shaping multipliers to better align dispatch incentives with system needs, particularly preserving storage for peak demand periods. As with the scaling factors, CAISO needs to provide analysis and detailed formulas showing how these values have been developed. However, SCE emphasizes that these design features should also be evaluated in conjunction with the most recent bid cost recovery (BCR) enhancements, as changes to the DEB formulation could materially influence uplift outcomes. SCE recommends that CAISO address the interplay between DEB and BCR in a future version of the straw proposal. 

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

SCE finds the Market Surveillance Committee’s proposed End-of-Horizon (EOH) bidding enhancement concept, allowing resources to specify a price for deviations from state-of-charge targets, to be conceptually valuable, but not yet sufficiently developed for implementation. The proposal introduces a new mechanism enabling storage operators to express the economic tradeoff associated with deviations from day-ahead schedules, which may improve alignment between dispatch outcomes and resource operator incentives.  

However, SCE identified several areas requiring further clarification. In particular, the interaction between this deviation pricing construct and ancillary service obligations, especially regulation and spinning reserves, remains unclear. These market products often cause deviations from planned state of charge, and it is uncertain how the proposed mechanism would coexist with these operational realities without creating conflicting incentives or unintended compensation outcomes. Furthermore, it is not clear whether the EOH price parameter will be used for the scheduling run or pricing run.  In other words, will the EOH price parameter be used for dispatch feasibility or price discovery? 

Additionally, SCE questions whether the proposal simplifies or instead introduces additional complexity to bidding and dispatch behavior. While the intent appears to be improving efficiency and reducing reliance on bid shaping to manage state of charge, SCE remains uncertain whether the proposed framework achieves this goal. SCE recommends that CAISO provide detailed, step-by-step examples illustrating how the mechanism would function under realistic market scenarios, including cases with significant ancillary service participation. 

SCE recommends CAISO apply a similar NGR bidding concept to the Day-Ahead market to address the time-horizon limitation of the IFM process to manage SOC to address inter-day opportunity costs by developing an optional end-of-day SOC value bid parameter.  This will provide CAISO with additional flexibility in the early morning to both meet demand and improve market efficiency.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

SCE supports the suite of outage reporting enhancements proposed by CAISO, including automatic acceptance of outage change requests, expanded flexibility for power minimum re-rates on test energy cards, improvements to out-of-service status functionality, and the introduction of partial outages for non-generating resources providing ancillary services. These enhancements are viewed as improvements that increase operational flexibility while improving how resources can better reflect its real-world capabilities. 

With regards to the automatic acceptance of outage change requests, SCE recommends CAISO incorporate prioritization logic to give higher priority based on when the outage is scheduled and apply the logic to existing overlapping outages for the same resource.  For example, an outage scheduled to occur the next day should have a higher priority than an outage scheduled for next week. Implementing a prioritization logic should allow CAISO to minimize any potential backlog of change requests in both Day-Ahead and Real-Time markets, increasing both operator and CAISO efficiency.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

SCE supports CAISO’s proposal to introduce additional parameters to represent storage nonlinearity more accurately, including fields capturing nonlinear energy limits and associated operating ranges. This enhancement will result in more accurate representations of the operating characteristics and resource reliability of storage resources and thereby will improve CAISO’s optimization modeling.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

SCE does not have any additional comments.

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

Terra-Gen appreciates the opportunity to provide feedback on the CAISO’s energy storage enhancements initiative. At a high level, Terra-Gen supports the second revised straw proposal’s movement towards improvements of the outage management system (OMS). Terra-Gen supports some elements of the straw proposal on nonlinearity representation but does find that there will need to be longer-term considerations for accurate representation. 

Terra-Gen finds that the proposed enhancements to the storage DEB better account for real-time conditions but still feature some outputs from day-ahead market runs. While this is not ideal, the proposed storage DEB formulation is a step in the right direction. 

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

Terra-Gen directionally supports the proposed storage DEB enhancement as it more accurately captures real-time opportunity costs relative to the status quo. While Terra-Gen previously supported the time-of-day (TOD) scaling concept relative to the other option presented (Example B over Example A), we did highlight our general concerns with both options as maintaining “an overly strict adherence to outdated outputs from the day-ahead market.” 

However, Terra-Gen appreciates the numerical example provided in CAISO’s presentation, including a comparison to how a new TOD shaped RT DEB is computed versus the status quo. Terra-Gen supports CAISO’s intent to reduce the risks of charging side mitigation and to better place storage within the bid stack even when mitigated. Placing storage in the correct location within the bid stack is important given the resource’s energy-limited status and the need to prioritize its SOC for peak hours later in the day. While the example provided is illustrative and not final, Terra-Gen supports the use of multipliers closer to 1.4 during off-peak hours to ensure SOC is not prematurely depleted.  

CAISO signaled a willingness on the May 18, 2026 meeting to consider scaling factors between 1-1.4 rather than 0.6-1.4. As discussed in Terra-Gen’s last round of comments, Terra-Gen would not support multipliers that would lower a DEB relative to the status quo (i.e., less than 1). Terra-Gen recommends that the “bottom” of the scaling factors be set at 1. These “lower” multipliers do not prohibit a resource from bidding in at a lower value than the DEB assuming that the bid is competitive and represents an operator’s representation of real-time opportunity costs. However, there may be instances where the sub-1 multiplier inappropriately mitigates a resource’s bid too low and still places it in the incorrect area of the bid stack. Within the illustrative example provided, this would be an issue during HE6-HE8, again highlighting the importance ensuring that the DEB does not cause unintended consequences such as depletion of valuable SOC during morning hours. 

Finally, Terra-Gen is pleased that this new storage DEB would apply equally to resources within EDAM/WEIM and those that are only in WEIM. While the WEIM-only formulation would use scaling factors associated with DGAP, this appears to be a reasonable path forward given that these resources by categorical definition cannot use scalars derived from the day-ahead market.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

Terra-Gen supports the 4 technology upgrades to the OMS. In particular, the automation accepting outage change requests immediately upon submission is a critical upgrade and we recommend that CAISO prioritize this upgrade over the power minimum rerates, also scheduled in 2026. For the other 2 upgrades that do not have a timeline proposed, Terra-Gen recommends that CAISO prioritize allowing non-null values for non-generation outage cards.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

Terra-Gen believes CAISO’s proposed representation of nonlinearity is a step in the right direction but that more work is needed longer-term to effectively represent nonlinearity. As Terra-Gen and others have repeatedly discussed, nonlinearity is a physical characteristic of battery systems that can (to a certain extent) be approximated and captured as additional fields within the Master File. It is therefore reasonable to create new Master File parameters that allow scheduling coordinators to represent these characteristics and allow the market to optimize around these limits, rather than the status quo which can mean that the market creates infeasible dispatch instructions. It is important that CAISO implement this change as soon as possible. While the proposal notes that this could be completed no earlier than Spring 2027, we recommend that CAISO stick to this timeframe as close as possible because of downstream impacts to operators. These impacts are discussed further below.  

In the long term, Terra-Gen recommends exploring additional methods to model nonlinearity. Nonlinearity can occur at different places within a facility’s SOC based on numerous factors, including the assumed rate of discharge. Discharging a facility at its rated Pmax will induce foldback (i.e., nonlinearity) at a different SOC level compared to if it was discharged at a lower Pmax over a longer period. Moreover, these systems are rarely dispatched at one single output over a sustained period of time. As a result, operators have limited visibility in real-time as the SOC of any given asset changes based on dispatch instructions provided through the market. 

This poses challenges for both resource operators and market operators. Resource operators will be incented to conservatively denote where nonlinearity occurs within the SOC as Master File parameters. Failing to do so may still result in infeasible dispatch operations from the market. However, conservatively estimating where nonlinearity occurs within a SOC could deprive the market of needed energy. There may be points along the upper operating limit between MIN_CONT_ENERGY_LIMIT and NL_MIN_ENERGY where the assumed maximum power output is below what a resource could achieve. Practically, this would deprive the market of needed MWs which may deleteriously impact reliability during stress conditions. 

While participants wait for the completion of a modeled solution, CAISO has discussed that limiting an operators receipt of infeasible dispatch instructions can be accommodated through updates to the Master File or utilizing the plant trouble outage card submissions. Using the plant trouble outage cards introduces additional risks. The California Public Utilities Commission (CPUC) is expected to issue a proposed decision (PD) in the current Resource Adequacy (RA) proceeding. The PD is anticipated to clarify counting rules for establishing a storage facility’s qualifying capacity (QC) and may implement an unforced capacity (UCAP) metric for thermal and storage resources. On the storage QC rules, prior CPUC Staff materials proposed to clarify that a storage resource’s QC should be equal to a power output that can be sustained over a 4-hour period without experiencing foldback. Regarding UCAP, a plant’s UCAP derate would be based on its forced outages utilizing data from CAISO. This poses a clear challenge and risk of double-penalty to a resource’s QC. The first accounting of nonlinearity will occur in the initial QC calculation. By taking forced outages when experiencing foldback, storage will see an additional derate to its QC via UCAP. Terra-Gen recommends that CAISO rethink this approach of using forced outages in the interim while a modeled solution is implemented. Instead, we recommend using the technical limit not in market model mentioned by CESA at the May 18, 2026 meeting.  

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

Vistra appreciates CAISO’s continued stakeholder engagement on storage design and modeling issues. The May 18, 2026, meeting focused on storage Default Energy Bid (DEB) enhancements, the Market Surveillance Committee’s Non-Generator Resource (NGR) bidding concept, and the second revised straw proposal on outage management.

Vistra supports the CAISO’s second revised straw proposal on outage management and suggests the outage management track be finalized and moved into implementation. Vistra requests CAISO consideration of a smaller scope Outage Management System (OMS) enhancement for additional overlapping outage capability on the Pmin (Load Max) parameter only descoping the request to exclude SOC parameters.

Vistra’s feedback on the May 18^th discussion focuses on the broader critical enhancements to the storage DEB (DEB reform) as well as the NGR end-of-hour bidding concept. Vistra does not support the Time-of-day (TOD) DEB framework that CAISO presented even with the revisions it added to try to resolve concerns; these did not resolve Vistra’s core concerns. Vistra urges CAISO to stakeholder an alternative approach that the stakeholder comments reflect some stakeholder interest in considering – hydro DEB. Vistra has provided an alternative storage DEB methodology in Question 6 leveraging the hydro DEB that can support daily use-limited storage or extended to multi-day or multi-month storage. Vistra respectfully requests CAISO stakeholder this alternative at the next meeting and includes it as an option in the next iteration.

The End-of-Hour (EOH) bidding concept could fundamentally change the role of storage hourly bids if the concept as discussed changes the hourly bids by shifting them away from interval price-quantity offers toward horizon bids that assign economic value to achieving an EOH state-of-charge target.[1] But an EOH horizon bid cannot replace interval bids for interval-by-interval dispatch and price formation, because interval bids reflect the marginal value of charging or discharging in each market interval while the optimization separately manages constraints across the horizon. A more workable enhancement would be to allow a EOH economic bid to work in conjunction with the EOH target, while treating the target as a self-schedule if no EOH economic bid is submitted. This approach would preserve the role of hourly bids rather than displacing them while enhancing SOC management via a horizon bid.

[1] CAISO allows daily and hourly bid components where the daily bids are a constant value across all hours (or intervals) in the market horizon and the hourly bids can vary across the hours within the horizon. In real-time, the hourly bids apply to 15 minute or 5 minute intervals within the hour and the daily bids apply constant value across the Fifteen Minute or Five Minute Market horizon. For simplicity across DAM and RTM, Vistra refers to interval bids (i.e., hourly bids) and horizon bids (i.e., daily bids). See Section 4.1 of Market Instruments BPM for more details.

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

Vistra does not support the revised time-of-day DEB proposal. Although CAISO modified the proposal in response to stakeholder concerns, those revisions do not resolve the core problem of how to mitigate daily use-limited storage resources in a manner consistent with technology-neutral mitigation principles and real-time opportunity costs.

Support for the time-of-day approach appears limited and qualified, and concerns remain regarding the false precision created by hourly shaping and the proposal’s reliance on administrative assumptions. Rather than addressing the core mitigation issue, the proposal layers multiple constructs—including gas-price floors, proxy assumptions, and administrative multipliers—onto a framework that recreates functionality already inherent in opportunity-cost-based mitigation but in a manner that introduces more error risk.

The relevant DEB question is how to represent opportunity costs under evolving real-time conditions, not how to replicate or forecast differences to the day-ahead expectations. A framework that relies on Integrated Forward Market (IFM) price expectations or administratively shaped hourly values is unlikely to accurately reflect the real-time opportunity costs facing use-limited storage resources, particularly where economically valuable discharge opportunities depend on intra-day conditions that cannot be forecast with precision ex ante.

Storage resources in the CAISO Extended Day-Ahead Market (EDAM) Balancing Authority Area (BAA), non-CAISO Extended Day-Ahead Market (EDAM) BAA, and in non-CAISO Western Energy Imbalance Market (WEIM) BAA face the same fundamental challenge of managing limited energy against dynamic real-time opportunity costs. These storage resources are evaluated for dispatch not only to meet their BAA needs but also to support EDAM or DAME transfers as well as whether to be decremented down when net importing or incremented up to support a net export. CAISO and non-CAISO storage resources should all can be evaluated consistently in determining the optimal footprint solution.

Creating separate mitigation constructs for similarly situated resources would introduce false distinctions without improving market outcomes. Mitigation instead should place similarly situated daily use-limited resources at the same position in the supply stack regardless of technology, whether the resource is hydro or battery storage. The hydro DEB methodology tunes the DEB to BAA pricing based on the fuel region and electric region that apply to the storage resource, which is an appropriate resource specific regional variation.

For these reasons, CAISO should avoid separate or location-specific DEB constructs for storage resources participating in the same integrated real-time market beyond those adopted in the hydro DEB and should ensure the price based opportunity cost used in setting the DEB is equivalent to the short term component used to value daily hydro’s uses.

An hourly shaped DEB does not address the core issue, which is preserving a resource’s limited daily dispatch opportunities and accurately representing the opportunity cost of discharging in one interval rather than another. A hydro-aligned approach better reflects those opportunity costs and avoids inconsistent treatment across resource types. CAISO itself explained when adopting the hydro framework that “[t]he CAISO worked with stakeholders to design the Short-Term component so that if the CAISO market dispatches a hydroelectric resource on a particular day, the market will implicitly recognize the hydroelectric resource’s daily use-limitations, and consequently, it is unlikely to dispatch the resource during the day for more than four hours.” CAISO also included a multiplier in the Short-Term component to address the same time-of-day issue raised here. That multiplier reflects the typical maximum number of hours per day that a resource with storage can run before exceeding its short-term use limitations. The same logic applies to daily use-limited storage resources, which are typically characterized by a four-hour use limitation for mitigation purposes.

Vistra therefore recommends that CAISO transition the storage DEB to a hydro-aligned DEB framework, retain the gas floor as an appropriate representation of replacement cost for stored energy in lieu of sunk charging costs, and incorporate variable operations and maintenance (VOM) costs as the minimum cycling spread or threshold as the difference between the Charge DEB and Discharge DEB.  CAISO should stakeholder the alternative hydro-aligned DEB framework described in Question 6 and include that option in the next iteration of this initiative. The CAISO should propose in its next iteration administratively determined default VOM based on observed registrations over the past six years.

This approach also provides a more durable path for longer-duration storage because the hydro framework can accommodate use limitations across longer horizons rather than only daily cycling assumptions. CAISO should not adopt time-of-day DEB constructs that add complexity, introduce increased risks due to false hourly precision, and value daily four-hour resources differently.

In parallel with any reforms to the storage DEB, CAISO should complete implementation of the Reference Level Change Request framework for use-limited resources, consistent with FERC Order No. 831 and the policy adopted in Commitment Cost and Default Energy Bid Enhancements. Opportunity costs may constitute short-run marginal costs for non-natural gas resources, and storage and hydro resources should have access to the same mechanisms to update those costs under rapidly changing real-time conditions. A hydro-aligned DEB without a workable Reference Level Change Request path would remain incomplete.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

Vistra supports efforts to enhance storage bidding so that bids better reflect value of use limitations outside the market horizon. CAISO’s May 18 discussion appears to frame the Market Surveillance Committee 2020 opinion around one option that was discussed in the opinion where the discussion was more nuanced.

Vistra supports introduction of an end-of-hour, or terminal, economic bid in addition to hourly bids. As the MSC has explained, the key distinction is between a primal constraint that limits the end-of-hour state of charge to a value most likely to represent a longer horizon and a dual construct that represents the different values of achieving different terminal conditions at the end of the optimization horizon.[1] The MSC was encouraging the CAISO to consider allowing storage to express a dollar value of energy to be applied in the objective function to the state of charge at the end of the final advisory interval stating that this makes hourly bids much simpler.

Vistra’s interpretation of the MSC opinion was that it encouraged considering adding the ability to place an economic value on achieving the end-of-hour target so that the market optimization when it calculates the shadow prices associated with relaxing constraints could better value the Scheduling Coordinator’s view of the cost of achieving that target instead of penalty prices more likely to drive uneconomic outcomes. In this light, the MSC opinion should be more narrowly read as suggesting an enhancement to the bidding paradigm not removing hourly bids.

Vistra supports enhancing the market to add a horizon (i.e., daily) bid to economically value the EOH SOC target because it better preserves efficient dispatch compared to the EOH parameter value at penalty price. By preserving the hourly bids and layering on the ability to economically value the EOH target, the market optimization can produce more efficient outcomes while maintaining reasonable price formation. As discussed in Question 1, the EOH concept would fundamentally change the role of storage bids if it were used to replace interval price-quantity offers with a horizon bid tied to an end-of-hour state-of-charge target in a manner that may undermine hourly outcomes and price formation. Importantly, if an EOH economic bid is added then there is a relevant DEB question on how mitigation should apply to the terminal value.

While CAISO implied during the meeting that it would interpolate interval-level approximations for market bids under this concept, Vistra does not support administratively set hourly bids. Interval bids must remain central to dispatch, and storage resources must continue to be able to set energy clearing prices when they are marginal under any revised design.

If CAISO proposes to use EOH parameters in a manner that displaces interval bids, it should demonstrate that storage can still set price when marginal and that the resulting interval dispatches remain economically efficient across intervals. A design that fails to preserve this principle would disconnect prices from marginal system conditions, undermine efficient price formation, and create asymmetrical treatment of storage relative to other resources.

A more workable design would allow an EOH economic horizon bid to operate in conjunction with the EOH target, while treating the target the same as today – a self-schedule – if no EOH economic bid is submitted. That approach would preserve the role of hourly bids rather than displacing them. Consistent with the MSC’s broader value-of-water logic, the better path forward is to maintain interval bidding and pricing, add an end-of-horizon value parameter to economically constrain terminal conditions, and avoid conflicting administrative constructs that work at cross-purposes. Under the hourly & horizon bid approach, the CAISO will still need to pursue the hourly bid DEB mitigation but will also need to explore whether floor or caps are needed to mitigate the EOH economic bid.

Finally, Vistra has long believed that stored water and stored energy function similarly from a market dispatch perspective even if the physical operations at the plant differ. The MSC opinion helps to root the discussion in that foundational similarity when they point out: “This is the philosophy of “value of water”, which places a value on energy left in storage at the end of the optimization’s time horizon”.[2] The core problem on placing either a value of water storage or value on energy storage are economically the same problem to resolve where the resource-specific value must be tuned to the length of those limitations. This is another reason aligning the storage DEB as proposed in Question 6 is reasonable.

[1] Market Surveillance Committee ESDER 4 Opinion, September 8, 2020, Page 5.

[2] Id.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

Vistra limits its outage management comments to a targeted refinement. CAISO’s second revised straw proposal on outage management moves in a constructive direction but eliminates from consideration one OMS improvement. The CAISO second revised straw proposal stated that they would no longer explore this proposal at this time. However, some expansion of additional functionality is needed to better reflect the operational realities of storage resources and meaningfully improve storage outage management. In the past, the CAISO implemented overlapping outage cards for Pmax in its OSI Enhancements 2021.[1] Vistra understands that adding this functionality to the three remaining NGR parameters (Load Max, Max Energy, and Min Energy) is a large implementation scope. After discussing, Vistra found that the largest difficulties in managing outages primarily affect the maximum capacity (Pmax) and the Minimum Capacity (Pmin) parameters. The Pmax can already reflect overlapping outages, and Vistra now only seeks extending this functionality to Pmin. Vistra recommends revising the scope and requests the CAISO review the feasibility of the smaller scope of merely expanding the functionality to Pmin (Load Max). Other than this narrow request, Vistra has no further comments on the outage enhancements currently.

[1] OSI21-BRQ200 added the Pmax overlapping outage card functionality for NG: “NGR Outage process efficiency. Allow overlapping outages on PMax (availability) while retaining restriction on Load Max, Max and Min Energy.” https://www.caiso.com/documents/businessrequirementsspecification-operationssystemimprovementsenhancements2021.pdf

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

Vistra supports CAISO’s direction toward a modeled solution for representing nonlinearity through a master file parameter or similar durable market-model enhancement. The approach described in the second revised straw proposal is broadly consistent with prior stakeholder input and appears to be the most durable long-term solution for accurately reflecting foldback and related operating limits in dispatch. Vistra encourages CAISO to prioritize timely implementation of this solution so that storage limitations are represented more accurately, transparently, and consistently in market systems.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below

Vistra respectfully requests that CAISO stakeholder an alternative approach to the real-time storage DEB. Under the alternative approach, CAISO would calculate the Charge Segment DEB and the Discharge Segment DEB using the hydro DEB framework adapted to the registered limitations of storage resources and then incorporate Variable Operations and Maintenance (VOM) costs to create a clear hurdle for moving from charge to discharge modes. Although Vistra believes prioritizing adequate charging best advances the design objective, Vistra is open to stakeholder feedback on the ordering of the methodology, including whether the same framework should be applied in reverse setting the Discharge DEB and then subtracting the VOM for the Charge DEB.

The methodology below is offered as an alternative approach for CAISO to stakeholder.

For daily limited storage resources:

For a Limited Energy Storage Resource (LESR), the only registered limitation applicable is for the daily use limitation. In this scenario, the Charge DEB should exclude the long-term component and only include the Day-Ahead peak power price. This would calculate the hydro DEB in the same manner as for other daily limited hydro resources as the higher of the gas floor or the price-based opportunity cost estimate (also called Short Term Component[1]).

Charge DEB=maxGasFloor,Short_Term_Component

Gas_Floor=UnitConversionFactor*HRpeaker*GPI*1.1

Short_Term_Component=DAL*multiplier

Where:

• UnitConversionFactor=0.001
• HRpeaker=11,068 Btu/KWh (same as hydro DEB)
• GPI is the Gas Price Index for the fuel region the storage resource is located
• Headroom scalar for the gas floor is 1.1.
• DAL is the Day-ahead (DA) power price index at local default electric pricing hub (L)
• Opportunity Cost multiplier is the same as the hydro DEB established multiplier 1.4

The Discharge DEB would then be adjusted to reflect the VOM cost of cycling, as follows:

Discharge DEB= Charge DEB+VOM

VOM costs should be based either on a new CAISO default value or on a registered value. Because CAISO now has roughly six years of registered VOM data compared to when it first adopted the storage DEB, it can now propose a reasonable default value for storage resources that do not register VOM. CAISO should establish that default based on currently registered VOM values while continuing to allow resources to register negotiated VOM values. In next iteration, CAISO should propose a default VOM.

Considerations for multi-day or multi-month storage:

This methodology can also accommodate longer-duration, multi-day, and multi-month energy storage resources. As reflected in Appendix D.8 of the BPM for Market Instruments, the hydro DEB framework already includes distinct components designed to reflect use limitations across different horizons, including daily, intra-monthly, monthly, and longer-term limitations using day-ahead, balance-of-month, and month-ahead prices. For that reason, calculating either the charge DEB using the hydro DEB calculation and the hydro DEB registration process provides a reasonable starting point for adapting a storage DEB for longer-duration resources rather than relying solely on daily cycling assumptions. This is the most durable approach to enhancing the storage DEB to work for storage of varying durations.

[1] CAISO storage DEB refers to a Price Based Opportunity Cost (PBOC) which is set by the Short Term Component.

1. Please provide a summary of your organization’s comments on the May 18, 2026 stakeholder meeting and the second revised straw proposal on Outage Management.

WPTF appreciates the opportunity to comment on the May 18^th working group meeting and revised straw proposal. Our comments focus primarily on the storage DEB and new NGR bidding concept. We support developing a DEB that can be consistently applied across all storage resources and that eliminates the need for a WEIM-specific storage DEB framework. However, WPTF remains concerned that the proposed approach is overly complex and may introduce unintended operational and market impacts. We encourage CAISO to continue exploring opportunities to simplify the framework while still achieving the stated policy objectives.

With regards to the DEB, WPTF recommends that CAISO: (1) consider not applying the TOD multiplier, and (2) provide additional analysis and transparency regarding the methodology being proposed to adjust DA prices to estimate RT prices for purposes of calculating the RT price based opportunity cost (PB OC) component of the DEB. We also request that CAISO clearly explain how the DEB will be adjusted for bid segments associated with charging.

With regards to the new NGR bidding concept; while we appreciate the creative thinking on alternative ways storage resources can bid into the market, we are concerned that the way the concept is being described (1) creates inefficient market outcomes and (2) adversely impacts price formation. Additionally, we believe that what the MSC initially discussed back in 2020 is just a slight enhancement to the already existing EOH SOC biddable parameter, not an entirely new bidding concept.  

2. Please provide your organization’s comments on the Draft Straw Proposal on Storage Default Energy Bids Enhancements.

WPTF appreciates the additional thought reflected in the revised proposal. While we support the objective of creating a consistent framework applicable to all storage resources, we remain concerned that the proposed methodology introduces unnecessary complexity through the use of multiple scalars and multipliers. These assumptions may ultimately produce inaccurate or ineffective DEBs and could create unintended adverse market outcomes. Additionally, there has been minimal discussion around how the CAISO plans to (1) estimate the scalars applied to the DA LMPs to forecast RT LMPs used to set the price based opportunity cost component and (2) set the TOD blocks and multipliers that make the final adjustment to the DEB. These are crucial elements in the CAISO’s proposal that have not been thoroughly discussed and if arbitrarily set or set based on inaccurate assumptions could create significant adverse impacts.

For example, it is our understanding the proposed TOD multiplier assumes a consistent hourly price shape across all days of the year. Specifically, assuming the TOD multiplier declines from 1.4 in HE16 to 0.6 in HE17 effectively assumes that market conditions and price patterns remain identical every day, which is inconsistent with actual market results. WPTF is concerned that this approach could still result in suboptimal dispatch outcomes.

As illustrated in the examples on slides 25 and 26, the opportunity cost initially establishes the DEB, but then the DEB abruptly declines to $25/MWh and remains at that value over a six-hour period solely because of the predefined TOD block and multiplier of 0.6. However, within that six-hour block, the resource can only sustain dispatch for four hours. As a result, the market would likely dispatch the resource during the first four hours of the block due to the sharp decline in the DEB and the uniform treatment across the six-hour horizon. This is problematic because: (1) the six-hour block exceeds the maximum duration capability of the storage resource, and (2) the block exceeds the market optimization horizon.

WPTF therefore strongly encourages CAISO to simplify the proposed framework and reconsider the use of the TOD multiplier. Specifically we wonder if it would be more effective to eliminate the TOD multiplier.

WPTF also has concerns regarding potential pricing impacts. If all resources were mitigated and storage resources were on the margin and thus setting prices, the proposed scalar approach could produce energy prices during net load peak hours that are lower than prices in off-peak hours. In addition, the proposal may not position storage appropriately within the bid stack relative to other resource types. For example, hydro resources with daily operating limitations currently rely on DEBs tied to hub prices, which would likely exceed 60% of the PB OC under the proposed methodology.

With respect to estimating PB OC, WPTF understands that the DA PB OC methodology for CAISO and EDAM resources would remain unchanged. However, for the RT PB OC, CAISO appears to be proposing a methodology that forecasts RT prices by applying an adjustment factor to DA prices. WPTF requests additional detail regarding how the adjustment will be calculated (i.e., how does the CAISO plan to calculate the scalars?).

Specifically, CAISO should clarify whether the adjustment is based on historical analysis over a specified time period, whether it relies on prior-day DA-to-RT spreads, or whether another methodology is being considered. For example, it could be that using more recent RT prices could provide a more accurate estimate.

Finally, during the stakeholder meeting CAISO noted that it intends to adjust the DEB so that bid segments associated with charging remain lower than those associated with discharging. WPTF requests that CAISO provide a clear and detailed explanation of how the charging-side DEB will be constructed and implemented.

3. Please provide your organization’s comments on the Overview of the NGR bidding concept put forth by the Market Surveillance Committee.

Based on the discussion during the stakeholder meeting, WPTF understands that CAISO may be considering a bidding construct in which storage offers reflect a resource’s willingness to increase or decrease from an initial state of charge, rather than directly reflecting willingness to charge or discharge energy in a given hour. This bidding construct would require resources to submit 3 bids in the day-ahead market – an initial SOC, a bid spread representing variable O&M costs, and a dollar value representing a willingness to end the day with a SOC higher or lower than the initial SOC. It would require 2 bids in the real-time market – bid spread representing variable O&M and a dollar per MWh value that represents willing to have a real-time SOC higher/lower than the DA SOC in the same hour. Assuming this interpretation is accurate, WPTF has several significant concerns with the proposed bidding concept.

This framework would fundamentally change the way storage offers are represented in the market relative to other resource types and products, making it extremely unclear what the bids represent. Furthermore, WPTF is concerned that this proposal could introduce significant and unintended price formation issues that have not yet been fully evaluated.

4. Please provide your organization’s comments on the Outage Reporting Enhancements section of the second revised straw proposal on Outage Management.

No additional comments at this time.

5. Please provide your organization’s comments on the Representation of Nonlinearity section of the second revised straw proposal on Outage Management.

WPTF continues to support representing nonlinearity through MF parameters.

6. Please provide any additional comments, feedback, or examples. You can upload supporting materials using the attachments field below