Comments on Draft revised final proposal

Day-ahead market enhancements

Comment period
Apr 06, 03:00 pm - Apr 24, 05:00 pm
Submitting organizations
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Submitted 04/24/2023, 04:22 pm


Rahul Kalaskar (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

AES Clean Energy (AES CE) Development appreciates the opportunity to provide comments on the Draft Revised Final Proposal (DRFP) put forth by the California Independent System Operator (CAISO or ISO) on April 6, as well as the stakeholder meetings held by the ISO on April 7th and 17th and the Addendum posted by the ISO on April 19th. AES CE believes that ISO has taken the right steps in introducing the imbalance reserve (IR) products in the day-ahead market to manage real-time uncertainty due to the penetration of renewable generation. However, we continue to be concerned about certain aspects of the ISO's proposal, as outlined below.

The ISO's proposed envelope equations for storage management augment the complexity of the day-ahead market design, making it challenging for storage assets to comprehend the IFM market awards.

The DRFP introduces new equations by the ISO for the state of charge required by a storage resource to support imbalance reserve awards in the day-ahead market. The ISO aims to anticipate the upper and lower values (or an envelope) for SOC to ensure that storage resources can supply imbalance reserve awards in the real-time market. Failure to do so could negatively impact reliability. The proposal's key aspect is the implementation of envelope equations that restrict the operation of storage resources by approximating upper and lower boundaries based on the asset's energy and IR schedules. The objective of the envelope equations is to restrict the amount of IR awarded to storage by ensuring that once the hypothetical SOC reaches the either limit, the market schedules the asset to charge or discharge depending on the limit reached before scheduling any further imbalance reserves.


AES CE has raised some concerns about the ISO's proposal. Firstly, the proposed envelope equations do not build upon the common understanding developed by stakeholders as part of the Energy Storage Enhancements (ESE) initiative and the efforts to represent the Regulation's impacts on SOC better. Consequently, the CAISO's proposal adds to the complexity of the numerous formulae currently employed for SOC management. Secondly, the proposal does not foster alignment among the different formulae used for SOC management, specifically the AS SOC constraint and SOC calculation. While AES CE acknowledges that the purposes of these formulae are distinct, the ISO should provide sufficient information to demonstrate how all these formulae would work together and confirm the use of different multipliers across the formulae.


AES CE acknowledges that the CAISO did not include the impact of IRU and IRD awards in the SOC equations because the ISO does not view these products as similar to regulation. The CAISO's demand profile indicates a constant need for ramping up and down in contiguous hours. On the other hand, the system needs regulation to balance supply and demand in sub-five-minute intervals, which could use both regulation-up and regulation-down in the same five-minute interval. As a result, awarding IRU and IRD to a single storage resource for the same hour would be impractical if its SOC could not sustain delivering energy for those awards. However, IFM awards for storage assets are already complicated to comprehend since IFM optimizes the storage assets within 24 hours. AES CE suggests that the CAISO consider sharing resource-specific constraints information in IFM so that storage assets can better understand the market outcomes. For instance, the CAISO could share information about the shadow price of the envelope equations indicating how frequently this constraint limits the IRU and IRD awards. Such data transparency will build confidence in these equations and also can be used by CAISO to educate the importance of introducing new techniques to manage storage assets.

The ISO should remove any provision that aims to incorporate the erroneous notion that IR is a component of RA or a successor product to RA.

As AES CE has previously stated, the IR product is a new solution that addresses the increasingly challenging issues related to the intra-hour variance between the day-ahead and real-time markets. In light of this, AES CE strongly recommends that the ISO removes all aspects of the imbalance reserve product, such as the "opt-in" mechanism, claw back, or SC trading, that is intended to address the misconception that the imbalance product will lead to a double payment under current RA contracts.

It is essential to understand that IR is not a part of RA or a successor product to RA, as AES CE and many other stakeholders have emphasized before. AES CE firmly holds this view that IR is entirely novel and has no connection to anything within the RA framework. As a result, AES CE urges the ISO to address the fundamental disagreement regarding the relationship between IR and the RA framework by explicitly clarifying that IR is a distinct product, RA assets do not currently provide the behavior it seeks to incentivize, and it is not a part of RA or an RA successor product.


A clarification is needed from the ISO on whether the $55/MWh offer cap for IR included in the proposal implies a cap on the price.


In the DAME Addendum posted on April 19th, the ISO proposes an innovative design approach for IR to eliminate mitigation for the IR Up product. To obviate the need for local market power mitigation (MPM), the ISO proposes reducing the offer cap from $247/MWh to $55/MWh. AES CE appreciates the ISO’s consideration of design approaches that would eliminate the need for local MPM; nevertheless, we are concerned with the sudden modification of the IR bid cap. The changes put forth by the ISO in the Addendum had not been socialized by the ISO in the previously held Workshops, nor were they put forth by other stakeholders presenting therein. Overall, the changes to the proposed IR bid cap materially dilute confidence in the product’s design given the lack of data (1) supporting the revision, which departs from the caps applied to other AS, and (2) estimating its impact on IR and other market products. As such, while we agree with the ISO’s conclusion that local MPM is unwarranted for the IR product, we believe that the sudden decrease of the IR bid cap is not aligned with the market efficiency principles the DAME initiative seeks to further through evidence-based product design. Thus, we request the ISO further document and justify the downward adjustments to the IR bid cap and reassess if $55/MWh is the adequate value.


It is unclear whether the inclusion of a $55/MWh offer cap for IR in the DAME Addendum will also cap the price of IR Up, which is co-optimized with energy and includes the opportunity cost of providing IR Up over energy. This is particularly important for energy-limited resources such as storage, which should not receive an IR Up award and be capped at the IR offer cap despite the energy price being higher than the IRU price. Therefore, AES CE requests the ISO to provide examples and clarify in the Final Proposal that the $55/MWh bid cap for IR will not limit the price of IR Up. This would be particularly concerning in hours when the energy price is more than double the IR offer cap.


Must offer obligations for IR products and VER offer obligations.

The CAISO's draft revised final proposal indicates that variable energy resources (VERs) would be eligible to provide both imbalance reserve up and down products. The current situation does not require VERs with RA to offer energy in IFM. Still, the implementation of DAME raises the question of whether they will be obligated to offer both energy and IRU for the portion of energy that is not self-scheduled. The proposal creates a complicated situation for must-offer obligation rules for VERs, as they currently do not have such obligations for ancillary services. Consequently, enforcing must-offer obligations for IRU and IRD on VERs could pose a challenge in terms of understanding and implementation. We recommend CAISO eliminate the must-offer obligations for IRU/IRD products for VERs but allow them to offer them in the market.

Bonneville Power Administration
Submitted 04/24/2023, 03:06 pm


Sara Eaton (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

The Bonneville Power Administration (Bonneville)[1] appreciates the opportunity to provide comments on the CAISO’s Draft Revised Final Proposal for the Day-Ahead Market Enhancements initiative. Bonneville would like to extend our appreciation of the additional time the CAISO has allocated to continuing discussion with stakeholders on these important changes to existing market design. As discussions around regionalization expand, it is more critical than ever for the CAISO to create proposals that meaningfully incorporate feedback from entities beyond the traditional CAISO footprint. The ultimate goal of market enhancements should be a fair, competitive market that makes minimal use of out-of-market actions and achieves equitable outcomes rather than prioritizing the requirements of any single stakeholder group.

Bonneville continues to support the CAISO’s inclusion of an Imbalance Reserve Down product in the market. Looking toward a future with increased renewable penetration and for stakeholders in the PNW, we see value in the IR Down product as another tool for the footprint to more efficiently allocate resources during periods of increased supply. If the prices for this product are relatively low, then we see that as an important price signal that can incent future behavior and resource development.

In the latest proposal, the CAISO added the ability to implement flexibility in regards to defining what constraints they will enforce in deployment scenarios. The CAISO did not have an explicit philosophy or set of parameters as to what would dictate when a constraint would be turned on or off. While this solution may resolve potential computational performance concerns that were raised by the CAISO and by stakeholders, it will give the CAISO increased market control, without predetermined limits or restrictions. In the stakeholder process, we did not hear any discussion surrounding potential limits or restrictions as to what would drive a constraint to be enforced or removed. We understand that there is a deliverability component to this determination. Bonneville requests that the CAISO provide clearly-defined limits as to what would drive the operator to remove a constraint. The ability to remove constraints has the possibility to impact LMPs, as deactivating congested nodes could suppress prices. In addition to the concerns about impacts on market outcomes, Bonneville is concerned that this increases the use of out-of-market actions which works against the transparent price formation Bonneville continues to advocate for. Bonneville requests that the CAISO commit to communicating these types of out-of-market actions as quickly and prominently as possible, particularly if actions are expected before the day-ahead market run. This level of transparency in regards to CAISO actions would help stakeholders to better understand what market conditions drive constraints to be removed.  

Along with allowing for flexibility in how constraints are enforced, the CAISO proposed the addition of the tunable parameter to control the proportion of imbalance reserve awards deployed in the deployment scenarios. The CAISO highlighted having the ability to adjust this parameter based on market simulation or operational experience. Bonneville understands the CAISO’s desire to have the tunable parameter to manage the need for reserve awards to be adjusted. However we have similar concerns with this proposal to those raised above, where the variables that would drive parameter changes would not be well-defined prior to adjustments and these market modifications would seem subjective without greater visibility into the driving forces. Bonneville requests that the CAISO commit open communication regarding changes to the tunable parameter as quickly and prominently as possible, particularly if actions are expected before the day ahead market run.

Additionally, the CAISO highlighted reviewing historical data for both the tunable parameter and the flexible application of constraints for deployment scenarios to inform future utilization of these tools. Bonneville is concerned that it could be difficult to extrapolate the impacts of adjustments, given the interaction between these two variables in determining imbalance reserve procurement and pricing impacts. Bonneville would recommend the CAISO examining the impact of each variable independent of each other, to best determine the impacts to market outcome.

Bonneville realizes that the CAISO has already extended this process beyond their initial timeline, but we continue to have concerns that this process is being rushed to meet the May Board of Governors and Governing Body meetings. Bonneville is significantly concerned that the focus on sticking with this particular timeline comes at the expense of thorough consideration for a critical aspect of the market design. Bonneville also feels that the inability to gain stakeholder consensus through this initiative stage will put greater risk on success through both FERC filings and with later adoption through EDAM. In other EDAM processes, stakeholders have flagged concerns about the conflict for CAISO in being the market operator, but also being a participating BAA. By introducing increased manual out-of-market actions through the flexibility to exercise system constraints, the conflict of roles and responsibility is exacerbated. Given that this issue of conflict was raised in other stakeholder processes, it would seem that this proposal could exacerbate those concerns in EDAM participation. Bonneville recognizes that the CAISO is working through tight timelines to stick to implementation schedules, and highlights that the latest proposal edits have not removed that process risk. If anything, the latest proposal, which adds increased subjectivity to operations, will likely have increased this risk.


Prior to seeking approval of this proposal, Bonneville asks for the CAISO to provide a set of known protocols as to how the CAISO would implement proposed flexibility constraints and reserve tuning functions and would expect CAISO to offer routine monitoring of the use and application of the constraint flexibility parameter. We would ask that the analysis of historical applications for the flexible constraints incorporate stakeholder input and discussion, to support an open and transparent process.  


Overall, Bonneville requests the CAISO consider delaying the timeline to garner greater support and understanding of the proposed changes. Doing so will reduce risks associated with FERC approval and EDAM implementation.

Prior to seeking board approval, Bonneville requests that the CAISO provide:

  • Well-defined parameters of what specific market conditions would dictate the CAISO to adjust constraints
  • Well-defined parameters of what specific market conditions would dictate the CAISO to change the tunable parameters
  • Timely notifications when adjustments are expected to be implemented
  • Thorough reviews and stakeholder engagement to assess the performance of the imbalance reserve product, and particularly when market adjustments are made.

In response to the CAISO’s addendum to the IR demand curve – Bonneville has concerns over the CAISO proposing these significant and late changes to the market design, without the opportunity for broader stakeholder discussion. The shift from the $247/MWh penalty price to the administrative ceiling of $55/MWh is a large change in pricing policy and moves further away from letting the market set the price. In the addendum, we did not see a significant justification for this shift and we have concerns that a historically-based price cap will not inherently support future changes in the market. Bonneville also has concerns that the discrepancy between the IR and FRP caps could result in unanticipated market outcomes. More broadly, we have concerns that CAISO could be put in a situation where they’re not procuring enough IR in advance and could be forced to take more out-of-market actions if they’re deficient in real-time.


The ultimate objective of this initiative was to create this IR product which market participants could provide to a system with increasing uncertainty, with the goal of reducing the reliance on out-of-market action. Bonneville believes it is important to keep that context in mind, as the latest proposal takes us further away from that initial goal of developing market-based solutions to resolve this issue.


[1] Bonneville is a federal power marketing administration within the U.S. Department of Energy that markets electric power from 31 federal hydroelectric projects and some non-federal projects in the Pacific Northwest with a nameplate capacity of 22,500 MW. Bonneville currently supplies around 30 percent of the power consumed in the Northwest. Bonneville also operates 15,000 miles of high voltage transmission that interconnects most of the other transmission systems in the Northwest with Canada and California. Bonneville is obligated by statute to serve Northwest municipalities, public utility districts, cooperatives and then other regional entities prior to selling power out of the region.


California Community Choice Association
Submitted 04/25/2023, 02:42 pm


Shawn-Dai Linderman (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

The California Community Choice Association (CalCCA) appreciates the California Independent System Operator (ISO) including the Resource Adequacy (RA) true-up mechanism and storage Residual Unit Commitment (RUC) participation rules in the Revised Final Proposal. CalCCA supports the RA true-up mechanism and proposes a modified process for its sunset.  CalCCA also generally supports the RUC participation rules but requests clarification regarding RA and non-RA bidding obligations and how the multipliers in the envelope equations will be determined.

The Revised Final Proposal includes a settlement mechanism that would allow contracting parties to opt-in to a RA capacity true-up in which the ISO will compensate the load-serving entity for opt-in RA capacity at the respective imbalance reserve capacity price (minus opportunity costs) and/or reliability capacity price. The ISO is proposing this as a transitional mechanism that would be in place for three years to allow time for existing contracts to roll off or be renegotiated. CalCCA supports the ISO’s proposed RA true-up mechanism, but recommends the ISO modify the three-year sunset date, given existing contracts may be long term, and expire later than three years into the future. Renegotiating contracts could result in increased costs given the constrained RA market.[1]

CalCCA recommends the following process for sunsetting the RA true-up mechanism:

  • The ISO implements the RA true-up functionality and keeps it in place for at least three years (e.g. 2025, 2026, and 2027 assuming a Fall 2024 implementation). After three years, if no market participant uses the functionality for one full year (e.g., no market participant uses it in 2028), the ISO would notify market participants of its intent to retire the functionality. The ISO would give market participants an opportunity to demonstrate that they will use the functionality in the upcoming year (e.g., in 2029) and if no party can demonstrate they will use it within the next year, the ISO would then remove the functionality.

The Revised Final Proposal also proposes allowing storage resources to participate in the RUC process. CalCCA supports this proposal. As storage resources become a larger and larger portion of the resource mix, barring storage from participating in RUC could cause market inefficiencies. The last bullet on slide 12 from the April 17, 2023 workshop seems to imply that the ISO would require RA and non-RA storage resource participation in RUC.[2] The ISO should clarify in its proposal that RA storage will be required to participate in RUC, while non-RA storage will have the ability to participate in RUC but not be required to participate in RUC. This maintains the current RUC bidding requirements that only require participation from RA resources.

During the April 17, 2023, workshop, the ISO presented how it will use envelope constraints to ensure RUC awards do not impact state-of-charge given storage cannot provide RUC capacity without state-of-charge. The ISO’s proposal to use envelope equations to prevent RUC awards that are inconsistent with actual state-of-charge or the upper/lower bounds from the envelope equations could be effective at ensuring storage can deliver on its RUC awards and other awards.  More discussion is needed, however, on how the ISO will set the multipliers in the envelope equations that will be used to estimate how much imbalance reserve capacity will be converted into energy and therefore impact state-of-charge. CalCCA requests additional discussion in the revised final proposal outlining how the ISO will choose to set the multiplier values and the impacts of any inconsistencies with setting the multiplier less than one and the nodal imbalance reserve design. 

[1]             The California Public Utilities Commission’s 2021 Resource Adequacy Report (Mar. 2023) demonstrates the tightness in the RA market causing increased costs: “The weighted average price of system RA for both seasons has increased each year, and at an accelerating pace. Average August prices were $3.13/kW-month in 2017 but increased each year thereafter. By 2021 the average price had risen to $8.07 kW/month, an increase of 158 percent over just 5 years.” Counterparties will be unlikely to renegotiate long term contracts to account for new revenue streams from ISO capacity payments as RA prices continue to increase dramatically – the result will be increased overall costs.   

[2]             See

California Department of Water Resources
Submitted 04/24/2023, 01:20 pm


Rodrigo (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

The California Department of Water Resources (CDWR) appreciates the opportunity to provide feedback on the changes to the CAISO’s current Day-Ahead Market Enhancements (DAME) draft revised final proposal (DRFP). CDWR continues to support the DAME initiative and most of the changes made in the draft revised final proposal.

CDWR reiterates it’s prior CRR comments.

CDWR does not oppose the CAISO’s proposal allocating EDAM CRR between the BAAs if the CAISO’s EDAM CRR meets the following criteria:

  1. In the DRFP CAISO states that: The trade-off between using transmission for energy or imbalance reserve flows depends on the relative difference between the marginal energy and imbalance reserve offers inside and outside the constrained area. The CAISO expects that the differences between imbalance reserve bid prices for the constrained vs. unconstrained areas generally will be much lower than the differences in energy bid prices for the constrained vs. unconstrained areas. This expectation is based on the lower cost of providing imbalance reserves compared to providing energy. As a result, CAISO expects the constrained transmission to be mostly used for energy. Thus, CAISO does not expect this to be a major issue. CDWR would like to know if CAISO could determine and present to the market participants the percentage of the cost of providing imbalance energy reserves vs the cost of providing energy.
  2. CDWR considers that the CAISO’s proposed method of calculation of the “displaced” congestion revenue from imbalance reserves Up Flow and Down Flow as described in paragraph 4.3.1 of the DAME DRFP aligns with the principles of congestion revenue calculation used in the DA market. 
  3. As previously expressed, CDWR is concerned that current CAISO’s EDAM DRFP to incorporate the marginal cost of congestion differences between source and sink for imbalance reserve deployment scenarios would exacerbate the DA CRR Revenue sufficiency.  The main role of the Track 1B CRR design feature, implemented in January 2019, was to protect the load demand from paying high benefits to the CRR Auction participants.  However, the latest CAISO Market Performance report shows in 2022, the CAISO’s DA CRR Auction Efficiency reached the highest levels seen prior to the Track 1B implementation.  Although CAISO expects the impact of imbalance reserves on the congestion contribution to be rather small, without a quantification of such impact, CDWR fears the redefinition of the CRR notional value to incorporate marginal cost of congestion differences between source and sink for imbalance reserve deployment scenarios would increase the current DA CRR Auction Efficiency.
  4. For reasons mentioned in paragraph #3 above, CDWR recommends that, before adding the CRR EDAM DRFP proposal to the current CRR DA design, the CAISO initiate a stakeholder process to: 1.  identify the root cause of the increases in the DA CRR auction efficiency, and 2. find and implement solutions to reduce these increases.


California Energy Storage Alliance
Submitted 04/24/2023, 04:47 pm


Sergio Dueñas (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

The California Energy Storage Alliance (CESA) appreciates the opportunity to provide comments on the Draft Revised Final Proposal (DRFP) put forth by the California Independent System Operator (CAISO or ISO) April 6 and discussed in the stakeholder meetings held by the ISO April 7th and 17th, as well as the Addendum posted by the ISO April 19th. While we recognize the ISO’s willingness to receive stakeholder feedback to develop the DRFP, CESA continues to have material concerns with elements of the ISO’s proposal, as detailed below.


The ISO’s proposed envelope equations concept adds further complexity to storage management, does not further alignment between various storage management approaches, and may overstep the boundaries set by the Federal Energy Regulatory Commission (FERC) regarding state-of-charge (SOC) management.


In the DRFP, the ISO includes new requirements for the amount of state of charge that a storage resource must hold to support imbalance reserve (IR) awards in the day-ahead market. This includes anticipating upper and lower values (or an envelope) for SOC to ensure that storage resources can deliver imbalance reserve awards in the real-time market, as failure to do so could have negative reliability implications. Key to this proposal is the introduction of the envelope equations which would constrain the operation of storage resources by estimating upper and lower bounds given the asset’s energy and IR schedules. The goal of the envelope equations is to limit how much IR is awarded to storage by ensuring that once the hypothetical SOC reaches either of the limits, the market will limit IR awards in preference for energy schedules to charge or discharge, depending on if the lower or upper limit is reached prior to scheduling any additional imbalance reserves.


CESA has some concerns with the ISO’s proposal. First, the ISO’s envelope equations proposal does not build upon the common understanding stakeholders have developed as part of the Energy Storage Enhancements (ESE) initiative and the efforts to better represent the impacts of Regulation on SOC. This, in turn, makes it so that the CAISO’s proposal adds further complexity to the myriad of formulae that are currently utilized for SOC management. Second, the CAISO’s proposal does not further alignment among the different formulae used for SOC management; namely, the AS SOC constraint and the SOC calculation. While CESA understands that the purposes of all these formulae may be different, whether or not there should be different purposes being achieved is an open policy question. CESA is not convinced that the SOC management approaches should be developed to meet different purposes based on the discussions. We are of the opinion that the ISO should provide enough information to demonstrate how all these formulae would work together and verify that the use of different multipliers across the formulae is needed. CAISO should explore more fully whether the SOC management approaches developed in ESE could be leveraged.


Third, CESA is concerned that the CAISO’s envelope proposal could be considered beyond the limits applied by FERC relative to SOC management under their storage participation policy. In Order 841, FERC established that “the energy limitations of electric storage resources will need to be factored into their market offers” and that “each RTO/ISO [shall] demonstrate how its existing market rules provide a means for energy-limited resources, including electric storage resources, to provide capacity [including] ways for energy-limited resources, such as electric storage resources, to represent their energy limitations through their offer prices, which, if allowed by the RTO/ISO, would not constitute economic withholding”. CESA considers that the establishment of envelope equations could be deemed an overstep to said FERC policy as they preempt the opportunity to reflect energy limitations through their bids and instead limit the number of hours storage could be awarded IR.


Finally, it is important to underscore the difficulty in supporting a proposal that has been so expeditiously developed and finalized despite its deeply technical nature and its material implications. It is particularly complex given the fact that the ISO has made different statements regarding the potential initial multipliers to be used in the envelope equations. The ISO would afford itself considerable discretion to adjust the configurable multipliers, which makes evaluating how this proposal would impact storage’s eligibility to participate in the proposed IR market difficult, if not impossible.


For these three reasons, CESA urges the ISO to (1) reconsider its proposal to apply these equations at this time (2) reassess the proposals put forth by other parties such as CESA (see below), and after which (3) if the ISO determines that the envelope equations are still preferable then direct further development of the concept.



The ISO should reconsider modifications to the formula that governs state-of-charge (SOC) calculations in the Day-Ahead (DA) market and the existing state-of-charge constraints.


As noted in prior comments, CESA understands that modifying the myriad of formulae that are involved in SOC management is challenging given the timeline of this initiative. As such, CESA recommends that within the present initiative the CAISO commits to, ad minima, incorporate the following changes:

  • CESA’s ad minima proposal:
    • Modify the DA SOC Calculation as follows: SOCi,tSOCi,t-1-(Pi,t++ηiPi,t-+μi,t+,RURUi,t+μi,t+,IRUIRUi,t-1+μi,t-,RDηiRDi,t+μi,t-,IRDηiIRDi,t-1image-20230424164602-1.png)   
      • Initially, equate the multipliers used for IRU and RU, and IRD and RD
        • Commit to update this as more data is available.
      • Commit on moving toward resource specific values as data allows, or if difficult move towards zonal values such as NP-15 and SP-15
    • Prior to implementation, commit to testing scenarios that would identify whether any inefficient or infeasible awards result from different multipliers in the SOC calculation than in the AS SOC constraint.


The ISO should eliminate any provision of its proposal that seeks to account for the mistaken idea that IR is part of RA or an RA successor product.


As CESA has previously stated, the IR product is a new product that is seeking to mitigate increasingly difficult challenges related to intra-hour variance that materializes between the day-ahead and real-time market runs. In this context, CESA has urged that the ISO should remove all features of the imbalance reserve product (be it the “opt-in” mechanism, a claw back, or a means for SC trading) that are intended to account for the mistaken idea that the imbalance product will cause a double payment under existing RA contracts.


IR, as clearly expressed before by CESA and several other stakeholders, is neither part of RA nor an “RA successor” product. CESA continues to hold this position: IR is completely new and unrelated to anything that currently exists in the RA framework. As a result, we urge the ISO to resolve the fundamental disagreement regarding the relationship between IR and the RA construct by explicitly clarifying that IR is a new product, that the behavior it seeks to incent is not currently provided by RA assets, that IR is not part of RA, and that IR is not an RA successor product.


The ISO should clarify if the newly included $55/MWh bid cap for IR implies a cap on the IR Up product’s price.


In the DAME Addendum posted April 19th, the ISO proposes a change to its design approach for IR in order to eliminate mitigation for the IR Up product. So as to obviate the need for local market power mitigation (MPM), the ISO proposes reducing the offer cap from $247/MWh to $55/MWh. CESA appreciates the ISO’s consideration of design approaches that would eliminate the need for local MPM; nevertheless, we are concerned with the sudden modification of the IR bid cap. The changes put forth by the ISO in the Addendum had not been socialized by the ISO in the previously held Workshops, nor were they put forth by other stakeholders presenting therein.


Overall, the changes to the proposed IR bid cap materially dilute confidence in the product’s design given the lack of data (1) supporting the revision, which departs from the caps applied to other AS, and (2) estimating its impact on IR and other market products. The changes also appear to materially dilute the signal that IR would send to ensure flexibility in the market, reducing the value of introducing a new product. As such, while we agree with the ISO’s conclusion that local MPM is unwarranted for the IR product, we request the ISO further document and justify the reduction to the IR bid cap. In addition, we request clarification on an important implication of this proposal.

Namely, it is unclear from the text of the Addendum whether the $55/MWh offer cap will imply a cap on the price of IR Up. This merits clarification given the fact that IR is co-optimized with energy. As such, the price for IR Up could not have an upper bound as it includes any lost opportunity cost of providing IR up over energy. As such, if the energy price is higher than the IR Up offer in that hour, the price of IR Up should not be bound to the $55/MWh bid cap. This is particularly important for storage as it is an energy-limited resource and, if storage is on the margin, it is critical to ensure these assets do not receive an IR Up award and are capped at the IR offer cap despite the fact that the energy price is significantly higher than the IRU price. In this context, CESA requests the ISO to address these potential circumstances through examples and to clarify in the Final Proposal that the $55/MWh bid cap for IR will not bound or limit the price of IR Up.

California ISO - Department of Market Monitoring
Submitted 04/24/2023, 04:33 pm


Roger Avalos (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:


The Department of Market Monitoring (DMM) appreciates the opportunity to comment on the Day-ahead Market Enhancements Revised Draft Final Proposal (Proposal).[1]  Changes included in the revised draft final proposal represent significant improvements over prior proposals.  As explained in these comments, DMM supports these changes, but offers recommendations for further refinements to the proposal.  DMM recognizes the ISO’s goal of moving forward with a day-ahead imbalance reserve product as a way of supporting the ISO’s EDAM proposal.  To the extent the ISO and stakeholders view a day ahead imbalance reserve product as essential for EDAM, we support moving forward given the significant benefits of EDAM.  However, as noted in prior comments, DMM does not think that imbalance reserves are an essential component of EDAM given the EDAM and WEIM resource sufficiency tests, and the EDAM net export transfer constraint.  


Imbalance reserve demand curve

The ISO now proposes to calculate an imbalance reserve demand curve with the same method as the flexible ramping product demand curve with two changes. First, the calculation will apply the ancillary service penalty price of $247 rather than the power balance violation penalty of $1,000 to the probability distribution. Second, the overall demand curve will also be capped at $55 per megawatt-hour.

While the new proposal is a significant improvement over prior proposals, the value of the imbalance reserves could still be significantly less than the newly proposed demand curve values. A demand curve that overvalues imbalance reserves will add unnecessary costs to the day-ahead market and could create arbitrage opportunities that reverse the imbalance reserve procurement and do not add value to the market.

The ISO proposes to periodically review market outcomes and adjust the demand curve to better reflect the value of imbalance reserves. DMM agrees this is prudent when implementing an imbalance reserve product in the day-ahead market.

To reiterate previous DMM comments, DMM does not think that imbalance reserves are an essential component of EDAM given the EDAM and WEIM resource sufficiency tests, and the EDAM net export transfer constraint. Nor would imbalance reserves be effective at ensuring deliverability of EDAM transfers.[2] Therefore, having imbalance reserve demand curve prices above the value of day-ahead reserves is not needed to support the EDAM.

Imbalance reserve 30-minute deliverability

The ISO proposes that imbalance reserves be deliverable as energy within 30-minutes rather than the previous proposal of 15-minutes. The ISO made this change after commenters, including DMM, and the MSC pointed out that the day-ahead to real-time net load uncertainty materializes over hours and not all within 15-minutes.

While 30-minute deliverability is an improvement over prior proposals, it is likely still too stringent. Ideally some reserves would be deliverable within 15-minutes, some within 30-minutes, 1-hour, 2-hours, and 3 hours etc. Having that many reserve products would be difficult to implement. Determining what length of time is the best to cover the overall day-ahead to real-time uncertainty is not straight forward.

DMM thinks an hourly product is a reasonable time frame to start with. This would align with the existing day-ahead energy and ancillary service products. Further, because much of the uncertainty materializes over hours, an hourly reserve would allow resources that are dispatchable hourly, and who can respond to day-ahead to real-time net load changes, to be able to be awarded and to be paid for imbalance reserves.

Similar to its approach with the demand curve, the ISO should continue analyzing the imbalance reserve deliverability timeframe to determine if adjustments could increase overall market efficiency.

Modeling transmission in the deployment scenarios

The ISO proposes to use wide discretion on which constraints to enforce in the imbalance reserve deployment scenarios. The ISO would be able to enforce or not enforce individual constraints in the deployment scenarios and will have a ‘tunable’ parameter that can reduce the overall amount of reserves modeled as flowing over the transmission system.

DMM thinks this is reasonable. How net load changes will materialize in real-time is uncertain. Precisely modeling potential flows based on one set of distribution factors that will likely be different than the actual distribution of net load changes across the system is not needed. Rather, ensuring that imbalance reserves are procured in a reasonable way, without undue amounts stranded behind transmission constraints is the purpose of the nodal procurement. The ISO’s current proposal is consistent with procuring imbalance reserves that are reasonably deliverable.

Further, the ability to remove some or all transmission constraints from the deployment scenarios will allow the ISO to protect the day-ahead market from any unintended and adverse outcomes caused by the nodal procurement of imbalance reserves.  This includes the ability to ameliorate potentially excessive costs in local areas caused by the demand curve overvaluing the imbalance reserve product.

The ISO should reconsider imbalance reserves resettlement

Imbalance reserves and the flexible ramping product are not the same products. The proposal’s changes to the demand curve and the 30-minute deliverability of reserves makes these products even more different. Incremental settlement, even if only on a portion of the schedule changes, between these two different products could lead to unintended consequences and complications.

For example, one complication could arise from the fact that real-time flexible ramping prices can rise higher than $55. A resource that bids its marginal costs in both the day-ahead and real-time markets could be awarded day-ahead imbalance reserves and real-time energy schedules. If the real-time flexible ramping price is higher than $55, the resource may be forced to buy back the imbalance reserve awards at a loss.

Instead of incremental settlement of two different products, DMM recommends the ISO consider only having financial consequences for imbalance reserves that are not available in real-time because of outages or a lack of real-time energy offers. This would keep incentives for imbalance reserves to submit real-time energy offers without the potential complications and unintended consequences of incremental settlement between two different products. One possibility is to have a “no pay” for day-ahead imbalance reserves plus a charge at the fifteen-minute market flexible ramping price for imbalances reserves not bid into the real-time market.

DMM supports the inclusion of storage resources in the residual unit commitment (RUC) process.

The draft revised final proposal includes provisions for energy storage resources to participate in the RUC process.  DMM supports the inclusion of storage resources in the RUC process.  However, because RUC awards will be constrained by the IFM state of charge, the proposal may lead to limited additional battery capacity awards in RUC.  Further, any RUC capacity awarded to storage resources may ultimately depend on real-time exceptional dispatch to ensure real-time availability.

DMM understands that the implication of a RUC reliability capacity up (RCU) or reliability capacity down (RCD) award for a storage resource is a real-time must offer obligation for the awarded hours, in the direction of the awarded capacity.  The notion of commitment does not exist for battery storage resources, and DMM supports this inclusion of storage capacity in RUC in this manner as it has potential to avoid more costly commitment of other generators in some scenarios.

The proposal includes extension of state of charge constraints used in the IFM to ensure that IFM awards remain deliverable in conjunction with RUC awards, and resource SOC limitations are not violated.  However, as the ISO clarified in an April 18, 2023 stakeholder presentation, RUC commitments will not impact state of charge.[3]  Therefore, while RUC may result in RCU and RCD awards where compatible with the level of SOC remaining after the IFM, the proposed RUC process may result in little additional real-time available capacity when a resource has exhausted SOC or has full SOC in a given hour after the IFM.  This holds even if it may be physically possible to provide additional capacity with additional charging or discharging schedules beyond those received in the IFM. 

The RUC process could award reliability capacity to batteries that depends on charging or discharging earlier in the day to manage state of charge.  When this occurs, real-time exceptional dispatch may be required to ensure deliverability of the awarded RUC capacity in real-time.  Even if a resource submits real-time energy offers for the hours of charging or discharging to manage state of charge, the time horizon of the real-time market optimization may be insufficient to ensure the necessary state of charge is available to support RUC schedules. Therefore, CAISO operators may need to issue exceptional dispatches to achieve and hold the required real-time state of charge to ensure availability of RUC capacity from storage resources when needed.

Accounting for ancillary services and reliability products in IFM and RUC state of charge constraints maximizes the likelihood that these awards will be deliverable in real-time.

In order to support feasible awards of all market products (energy, ancillary services, and reliability products), the ISO proposes to modify existing constraints and implement new constraints on state of charge in the IFM and RUC processes in the day-ahead market.

DMM supports the expansion of the day-ahead ancillary services state of charge constraint to include IRU and IRD in the IFM, and to further include RCU and RCD in ancillary services state of charge constraints in RUC.  These constraints are important to ensure that awards for ancillary services and reliability products are feasible for an hour in the day-ahead market, as required by the CAISO tariff for ancillary services.

The ISO’s proposed “envelope constraints” appear to be a reasonable approach to ensure that the impacts of awards in opposite directions do not cancel out, and that the impacts of energy, IRU, and IRD awards within an hour would not exceed the limitations of the resource.  This may be important since, as the ISO notes, when IRU or IRD are deployed as energy in real-time, this is likely to occur in a single direction even when awards may exist in both directions.[4]

The use of separate envelope constraints may be especially important when estimates of hourly deployment probability are poorly estimated or do not vary among products or hours of the day.  In these scenarios, impacts reflected in a single constraint may be more likely to cancel out in a way that does not reflect their true deployment probability in a given direction.

Where the SOC is modeled, such as in the IFM, using a single constraint similar to that modeling the impacts of regulation awards on state of charge may yield similar results when hourly specific multipliers are used and sufficiently different across products.[5]  This approach appears more similar to one proposed by some stakeholders, but would require further modification to the proposal to include SOC modeling in RUC.

In general, the use of multipliers and constraints in the day-ahead market processes to estimate state of charge impacts of day-ahead awards may improve - but will not guarantee - the real-time deliverability of day-ahead storage awards of any product.  Estimating multipliers specific to each product and hour seems likely to provide the best estimate of real-time availability.  However, as with RUC awards, the availability of IRU and IRD capacity in real-time may ultimately rely on real-time exceptional dispatch to ensure real-time deliverability.

Finally, as with the implementation of any new or modified market constraint, the addition of new or modified state of charge constraints has potential to interact in unexpected ways with existing constraints.  DMM recommends the ISO carefully monitor the implementation of the newly proposed SOC constraints, and be prepared to quickly modify the implementation as needed to address any unexpected market outcomes.




[1] Day-Ahead Market Enhancements Revised Draft Final Proposal, California ISO, April 6, 2023: Day-ahead Market Enhancements Addendum: Imbalance Reserve Demand Curve:

[2] Comments on Day-Ahead Market Enhancements March 2023 Workshops, DMM, March 31, 2023:

[3] See Presentation – Day-Ahead Market Enhancements – April 17, 2023, Slide 18, California ISO:

[4] Day-Ahead Market Enhancements: Draft Revised Final Proposal, p.56, California ISO, April 6, 2023:

[5] Energy Storage Enhancements: Final Proposal, p.11, California ISO, October 27, 2022:

Los Angeles Department of Water and Power
Submitted 04/24/2023, 06:01 pm

Submitted on behalf of
Los Angeles Department of Water and Power


Stuart Kelly (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

See attached file

Middle River Power, LLC
Submitted 04/24/2023, 02:50 pm


Brian Theaker (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

Middle River Power (“MRP”) appreciates the opportunity to provide comments on the April 6, 2023 Draft Revised Final Proposal (“DRFP”) and the April 19, 2023 Addendum: Imbalance Reserve Demand Curve (“Addendum”). 

Prior to the DRFP and the Addendum, MRP mostly supported the majority of the CAISO’s Draft Final Proposal.  MRP also appreciates the additional time the CAISO spent discussing stakeholders’ concerns with the nodal approach to procuring imbalance reserves.  However, MRP believes the CAISO has not sufficiently discussed or justified the extensive and significant last-minute changes presented in the DRFP and the Addendum.  Therefore, MRP can no longer support the DAME proposal in its current form and may oppose the proposal at the May Board of Governors meeting due to the lack of process and discussion regarding the significant and last-minute changes in the DRFP and Addendum.  While MRP appreciates the additional time spent in this initative, the myriad changes proposed at the eleventh hour are mostly unrelated to consideration of the nodal and zonal approaches.  MRP believes it is unreasonable and improper to make such significant changes without fully vetting and justifying them through the stakeholder process - now four years long - prior to taking the revised propsoal to the Board.

Consequently, MRP respectfully urges the CAISO to further discuss with and justify those changes to market participants before seeking approval of those changes from its Board of Governors.  Conversely, while MRP does not recommend proceeding with the DAME design as recently and extensively modified, if the CAISO believes it is necessary to seek Board approval of DAME in May, MRP recommends that the CAISO strip out all of the features revised or added in the DRFP and Addendum, present the previous (and more thoroughly vetted) DAME design to its Board for approval in May, and continue to discuss the recent proposed modifications with market participants and stakeholders more fully before seeking to incorporate those modifications in the DAME design.

MRP has concerns with the following aspects of the DRFP and addendum.

First, the CAISO proposes to implement flexibility to enforce or not enforce constraints to optimize solution performance or mitigate excessive congestion costs.  However, the CAISO provides few details with regards to what metrics will be used to determine what subset of constraints will be enforced.  MRP requests the CAISO provide additional details as to how the CAISO will determine which constraints to enforce both during the market simulation as well as in the daily markets following implementation of the DAME software.  Further, MRP requests the CAISO provide additional information and transparency during the market simulation to allow market participants to fully understand the impact of not enforcing various constraints.  MRP also requests the CAISO remain open to scheduling additional iterations of the market simulation as may be required.  Finally, the CAISO should codify the criteria and processes the CAISO will use to determine which constraints to enforce and to notify market participants both in the implementing tariff language and in the transmittal letter to FERC.

Second, the CAISO proposes to implement a tunable parameter that would allow it to scale the amount of energy flow associated with imbalance reserves.  While this is a novel approach to addressing concerns about imbalance reserves creating “excessive” congestion costs, and while the CAISO proposes to set this parameter to one (1) initially, details regarding the process and evaluation criteria that the CAISO will use for changing this parameter and communicating the changes to market participants remains undeveloped.  Moreover, given that the implications of setting this parameter to something other than “one” or “zero” have not been fully discussed, MRP is unsure that “scaling” the energy flow from all imbalance reserves is the right way to address concerns about congestion that may result from the unlikely deployment of energy from all imbalance reserves.  When energy is deployed from imbalance reserves, MRP expects it will be deployed based on the price of energy bids associated with the imbalance reserves, meaning energy will be deployed from some, but not all, imbalance reserve capacity. Contrary to this approach, the CAISO’s proposal would assume that some amount of energy is deployed from all imbalance reserve capacity.  Consequently, it’s not clear to MRP that this tunable parameter would accomplish what MRP believes the CAISO intends it to accomplish.   

Third, the CAISO proposes to create a process for suppliers and load serving entities (“LSEs”) to identify the quantity of RA capacity that would be included in a CAISO-provided transitional “true-up” settlement mechanism.  While MRP understands the concept, and appreciates the CAISO’s efforts to facilitate such settlement, this proposal isn’t fully baked.  RA capacity is not always transacted only once.  Buyers may resell such RA capacity to other buyers who may then sell such capacity again.  Additionally, RA capacity may not be sold to the same buyer throughout the entire year.  MRP believes reporting such transactions to the CAISO via the CIDI system would be burdensome, and that tracking all transactions would be difficult.

Fourth, as the discussion from the April 17, 2023 workshop on the interaction of energy storage with the DAME DRFP indicates, significant questions and issues remain with regards to the state of charge “envelope equations”, and, in particular, the state of charge multiplier used for imbalance reserves in those equations.  MRP appreciates the CAISO’s frank discussion of the proposed multiplier, noting that the current proposal offers a 0.2 multiplier, which would allow storage resources to provide imbalance reserves up to 20 hours per day,[1] but also opining that a multiplier of 0.85 may be more appropriate.  The significant difference between these two values is prima facie evidence of the need for more discussion on this topic.   Moreover, while MRP appreciates the CAISO acknowledging that the final proposal is not yet set and the Business Practice Manuals will document the hourly multipliers and the methodology that will be used to set the multipliers,[2] MRP expects that the CAISO will determine that methodology in conjunction with stakeholders and not on its own.  Further, as with the other tunable parameters, the CAISO must develop, with stakeholders, the appropriate process for modifying the state of charge parameter, and codify that process and the evaluation criterria used, preferably in its tariff.   

Fifth, MRP strongly objects to the change proposed in the Addendum – to subject all imbalance reserve procurement to a demand curve but impose an administrative offer cap of $55/MW on imbalance reserve procurement.  This proposal marks a radical last-minute departure both from the DAME design and, moreover, a departure from the thorough vetting process that the CAISO had heretofore gone to great lengths with market participants over the last four years since the initiative was launched in June 2019.  The CAISO has neither discussed with nor justified this new proposal to market participants.  This proposal, which marks the second large change to the process by which the CAISO will procure imbalance reserves in just the last two weeks, is too large and insufficiently-justified a change to the DAME design for the CAISO to proceed without further market participant vetting.   With regards to this change, MRP takes no comfort in the CAISO’s suggestion that this change eliminates the need to apply local market power mitigation to imbalance reserves bids.[3]  It would be more accurate to say instead that the CAISO’s new proposal imposes full-time, system-wide market power mitigation on imbalance reserve procurement without providing any evidence that market power warranting that kind of extensive mitigation exists.

Finally, the CAISO proposes to allow energy storage resources to participate in the residual unit commitment (“RUC”) process.  Stakeholders raised several important concerns during the workshop meeting. One such concern was how RUC would incorporate both charging and discharging capacity with a $0 RUC bid. Another equally concerning issue raised was if storage resources would be allowed to bid in negatively-priced RUC for charging bids.  MRP agrees with many other stakeholders that this RUC proposal, which is being added effectively at the very last meeting on DAME, is also not yet fully baked. 

In sum, while MRP largely supports the imbalance reserve product and does not wish to delay its deployment simply for the sake of delay, the significant new modifications the CAISO added in the DRFP have not been fully considered.  If the CAISO wishes to take the DAME initiative to its Board in May, it should remove the newly-added items.  If the CAISO wishes to move forward with the DAME initiative as amended in the DRFP and the Addendum, it should hold additional stakeholder meetings before finalizing the design and taking it to its Board. 

MRP thanks the CAISO for the opportunity to provide these comments.

[1] CAISO presentation for the April 17, 2023 workshop at slide 28.

[2] CAISO presentation for the April 17, 2023 workshop at slide 25.

[3] Addendum at page 3.

NV Energy
Submitted 04/24/2023, 02:01 pm


Lindsey Schlekeway (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

NV Energy views the CAISO’s new final proposal as an attempt at a compromise from a wide range of stakeholder feedback. While NV Energy is more supportive of this more conservative approach for the Imbalance Reserve Product (“IRP”), there are still concerns to address prior to moving this design to a Board decision. Specifically, CAISO has not provided analytical support for the IRP down product, the IRP impact on market prices, or the computational time that this product will require. A significant concern is the newly proposed flexibility that was incorporated into the IRP which could allow CAISO to control and determine market prices. It is important to note that the IRP was designed specifically to address operational issues in the CAISO Balancing Authority Area, therefore, it is particularly concerning that the CAISO would request this level of discretion.

CAISO stated that with the inclusion of the additional market runs from the EDAM design would push the Day Ahead Market results to 2pm and that the IRP would add additional processing time. However, CAISO has not indicated how much additional delay the IRP will add to producing the Day Ahead Market results. The timing of the Day Ahead Market results impacts gas procurement; therefore, it is important that this information be provided to stakeholders at the earliest possible time so that they can evaluate the tradeoffs between the benefits from the product and any consequences to other processes.

NV Energy is more supportive of the $247/MWh capped demand curve approach than the previous proposal but remains concerned that the proposed IRP will procure too much of the product for uncertainty in the Day Ahead Market, which would impact prices not only in the Day Ahead Market, but also in the Energy Imbalance Market (“EIM”). CAISO is still pursuing a product design that is different than any other organized market. To date, CAISO has not provided analysis or a study that shows the unit commitment level for EDAM and the resulting pricing impacts to the Day Ahead and Real Time Market prices from this product. Major enhancements should not be introduced without sufficient quantitative analysis to illustrate the need and the impact they would likely have on the market and the customers that the market serves. Therefore, NV Energy reiterates that CAISO remove the IRP from a Phase 1 of the DAME initiative and EDAM to carefully consider each design element and its impact to the market and to provide sufficient time for the CAISO to provide analysis that supports the need of the product and illustrates the impact of the product on the Day Ahead Market and the EIM. NV Energy does not believe that an IRP is necessary to be implemented before the EDAM market because the EIM was in operation with a resource sufficiency test years before the Flexible Ramping Product was introduced to the market. Thus, NV Energy believes there is a proven path for the EDAM to begin implementation before another market product is introduced. Furthermore, NV Energy suggests that CAISO consider higher-priority enhancements to the DAME initiative, such as an extended Short Term Unit Commitment (“STUC”) time horizon that could commit additional capacity if it is determined to be necessary in order to pass the Real Time Resource Sufficiency test.  NV Energy believes this route would be the cleanest option to prevent any delay to the EDAM implementation timeline.


Imbalance Reserve:

In this final proposal, CAISO has modified the nodal procurement with flexible activation/deactivation of individual transmission constraints to improve computational time and address other stakeholder concerns. Additionally, CAISO proposes to implement a tunable parameter to define the amount of IRP that is deployed to mitigate the concerns about congestion costs. The tunable deployment parameter would essentially allow CAISO to control the IRP pricing, without the ability for other stakeholders to weigh in on this determination. This would provide less pricing transparency than the current IR design. NV Energy is not aware of another market product where CAISO has this much flexibility in order to control market prices. While NV Energy appreciates CAISO’s recognition that this product will need tuning in order to achieve the highest benefits to customers, NV Energy strongly opposes this newly proposed flexibility. This proposal is an indication that the product design is not complete and requires further analysis and stakeholder discussion. NV Energy recommends that CAISO provide a process that they will use in order to update the transmission constraints and CAISO should only update the tunable deployment parameter following an expedited stakeholder process.  This product could impact customer rates and NV Energy believes it would be inappropriate for the market operator that is also the largest balancing authority area to have control over a component that could impact rates in market as a whole, especially with respect to the external EIM Entities.

During the MSC meeting, the MSC members noted that the proposed 15-minute ramp requirement for the IRP could lead towards excess commitment of capacity, inflated energy and IRP prices, and an exclusion of some offline capacity. Therefore, CAISO updated the final proposal to expand the IRP to include a resource’s 30-minute ramp capability as long as the resource is 15 minute dispatchable. NV Energy is supportive of this expansion but remains concerned that this may still result in an exclusion of some offline capacity. 

The final proposal still includes the procurement of downward capacity. NV Energy strongly opposes the procurement of the downward product especially since other markets only procure uncertainty in the upward direction and CAISO has not provided any data supporting the need or net benefit of downward procurement in its proposed design. There is a concern that the currently proposed product may increase the processing time, and delay the day ahead market results, which might cause further inefficiencies with gas procurement and scheduling on the timeframe of the posted results. Therefore, NV Energy requests removal of downward product until the need for such a product is demonstrated with proper evaluation of the potential costs and benefits. Regardless, CAISO must provide the anticipated timeframe in which the Day Ahead results will be posted in order for stakeholders to address the efficacy of the proposed enhancements.  

Finally, CAISO proposed a revision to its final IRP design to collect congestion revenue through an IR uplift. While NV Energy does not support the proposed congestion proposal, CAISO should consider if it would be appropriate for load to pay for congestion of an uncertainty product when that uncertainty is not likely to materialize. More time is needed to understand the implications of this proposed design element and whether other markets collect congestion revenue for an uncertainty product.


Demand Curve

NV Energy supports the conservative demand curve approach with the price cap at $247/MWh for the IRP to mirror the demand curve used for the EIM at the onset of the implementation for this product. CAISO and stakeholders should reassess the price cap following a detailed analysis report regarding the performance of the product in a future stakeholder process.

CAISO also proposes that the uncertainty requirement used in the demand curve would include the EDAM diversity benefit. NV Energy is supportive of lowering the requirement from applying a diversity benefit, however, CAISO should provide a calculation that illustrates how the benefit will be applied to each BAA.




To reiterate, NV Energy is supportive of the more conservative approach that CAISO has taken in this final proposal.  However, NV Energy is concerned that this may result in increased RUC operator biasing and recommends that CAISO include and explain the RUC biasing policy in the final proposal.  Additionally, following the implementation of the Day Ahead Market Enhancements CAISO should provide a report on the percentage of IRP procured in Day Ahead in comparison with the IFM and RUC load biases.

In previous comments, NV Energy proposed that CAISO consider a RUC run with the transfers locked between each Balancing Authority while counting the transfers that occurred in the Integrated Forward Market (“IFM”). NV Energy believes this proposal might also be beneficial considering the CAISO Balancing Authority might be the only area that includes convergence bidding. During the workshops, it was apparent that stakeholders are concerned that the current CAISO proposal may allow virtual bidders to take advantage of IRP pricing issues, which could significantly increase the quantity that is procured in RUC. This concern illustrates the need for CAISO to run studies to determine the pricing impacts of its proposed IRP and is another reason NV Energy does not support the current proposed RUC run to use all capacity within the EDAM footprint. 

Pacific Gas & Electric
Submitted 04/26/2023, 03:07 pm


JK Wang (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

PG&E appreciates the CAISO’s efforts to address Stakeholders’ concerns by revising the Final Proposal of Day-ahead Market Enhancements (DAME). While PG&E agrees with the CAISO’s prioritization of  problems addressed in the latest Draft Revised Final Proposal (DRFP), PG&E opposes two elements  that could lead to adverse consequences in the Extended Day-Ahead Market (E-DAM).


  1. Real-Time Market Ramp Deviation Settlement. PG&E continues to oppose settling Imbalance Reserves (IBR) against real-time Flexible Ramp Products (FRP) awards and energy movement. In previous comments, PG&E stated that buyback options are not applicable to capacity products, including IBR, because awards of capacity products are not schedules and cannot have a “deviation” in the sequential markets. In addition, deviation settlement of FRP and IBR is on an unequal basis. The price of IBR includes both the resource’s bid cost for capacity and the opportunity cost of not providing energy, whereas the price of FRP does not include an explicit bid cost.[1] 

The recent changes in the DRFP and the Addendum makes the deviation settlement nonviable. First, the CAISO proposes in the DRFP to change the bidding requirement for IBR from 15-minute ramping capable resources to 30-minute[2]. Given that FRP is a 15-min product, it is economically inconsistent to settle IBR against FRP, since they are products of different qualities. Second, the CAISO proposes in the Addendum to reduce the cap of IBR demand curve to $55/MWh.[3] PG&E is seriously concerned that settling IBR against FRP will disincentivize bids for IBR, considering the resources would have been compensated for FRP, which is capped at a much higher price ($247/MWh) in real-time. In an extended day-ahead market, where only California Resource Adequacy (RA) capacity is required to bid for IBR, PG&E is concerned that the deviation settlement will economically disadvantage California.    

  1. Modeling Imbalance Reserves in Deployment Scenarios. The CAISO’s proposal “would implement a tunable parameter to define the proportion of imbalance reserve awards that are ‘deployed’ with resulting flows in the deployment scenarios.”[4] PG&E opposes this approach.

PG&E understands that the CAISO would like to retain a nodal procurement design to ensure IBR deliverability. The proposed change appears as a compromise to address the concerns in a nodal design about (1) IBR-induced congestion costs and (2) over-reserving transmission capacity, both of which are due to uncertainties likely to realize below IBR’s procurement target (i.e., 95% of historical uncertainties).  PG&E agrees that those are valid concerns.

However, PG&E is concerned that this approach cannot effectively address IBR induced congestion costs unless the parameter is set to a very low value, which increases risk of IBR undeliverability in real-time. In addition, this approach would deteriorate transparency of market operation and have unforeseen impact on the Congestion Revenue Rights (CRR) process.

PG&E requests the CAISO reassess these two critical issues. PG&E believes that it is important to put forward practicable solutions without delaying E-DAM’s implementation and provides the following suggestions for the CAISO to consider in developing the next proposal:   

  1. Real-Time Market Settlement. The CAISO should ensure a settlement process for IBR that properly incentivizes bids for IBR and does not violate economic principles. PG&E believes that IBR awards should be fulfilled with their Real-Time Must Offer Obligation (RT MOO) and be eligible to receive additional compensation for opportunity cost if realized in FRP in real-time. Attached in our comments is a settlement process that PG&E shared with the CAISO in July 2022 and Jan 2023.
  2. Deployment scenarios. PG&E requests the CAISO apply transmission penalty prices to deployment scenarios, which can simultaneously address congestion costs induced from IBR while guaranteeing IBR’s deliverability. Transmission penalty prices will drive day-ahead market optimization to schedules IBR flows on other transmission lines when the deployment scenarios are about to bind.  Without the need of setting values for 24 hours in the day-ahead market and tune it periodically, using transmission penalty prices also improves market predictability and reduces impact on interactive products (e.g., A/S and CRR). Other ISOs have been using transmission penalty prices successfully to address similar issues.

In addition to these two critical issues, PG&E finds the following two elements need further justification. 

Demand curve. PG&E supports the CAISO to apply a lower value ($55/MWh) to the cap of IBR’s demand curve but requests the CAISO to provide more information with data on how this value is selected. PG&E requests the CAISO monitor the bids and awards of IBR after DAME’s implementation and allow this value to be revisited in the future. In addition, PG&E understands that the demand curve approach will not allow IBR procurement to be prioritized over LPT export awards in the Integrated Forward Market (IFM) and believes it is critical for the CAISO to ensure that LPT exports will be curtailed before native IBR awards in the RUC if the market runs into infeasibility. Finally, PG&E requests the CAISO provide details of how the demand curve is designed, i.e., for the values of segments, in the phase of implementation.  

30-Min Ramp Requirement. PG&E requests the CAISO provide justification for the design element that “Imbalance reserve awards would be capped at the resource’s 30-minute ramping capability”[5]. PG&E agrees that the 15-min ramp requirement for IBR bids in previous DAME proposals  is overly restrictive and believes relaxing this requirement to 30-min will alleviate the problems of supply scarcity and price increases. However, the DRFP does not explain how the CAISO decides the amount of ramp needed to fulfill the uncertainties need in the market and that could be offered by generation fleets in the E-DAM. PG&E requests the CAISO to provide the data and analyses that support the change to 30 minutes.


[1] PG&E comments to Draft Final Proposal – Day-Ahead Market Enhancement, Dec 21, 2022. 

PG&E comments on Fourth revised straw proposal and Nov 1, 2022 stakeholder call discussion

[2] CAISO, Day-Ahead Market Enhancements: Draft Revised Final Proposal, April 2023

[3] CAISO, Day-Ahead Market Enhancements: Addendum – Imbalance Reserves Demand Curve, April 19, 2023

[4] I.d.1.

[5] I.d. 2.


Submitted 04/24/2023, 02:58 pm


Vijay Singh (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

In the last round of comments there were five design features, highlighted below, that PacifiCorp believed warranted further discussion or reconsideration for the Draft Revised Final Proposal:

  • Minimizing risks from deployment scenarios
  • Capacity eligible to provide imbalance reserves
  • Structure of the imbalance reserve demand curve
  • Use of tunable parameters
  • Market clearing time

PacifiCorp will further elaborate on the changes below and offer suggestions for the Final Proposal.

Minimizing risks from deployment scenarios

The CAISO has proposed flexibly applying constraints in the deployment scenarios and has committed to working with EDAM BAAs to identify those constraints. PacifiCorp supports this change. While PacifiCorp is in favor of the use of deployment scenarios, stakeholders have brought forth valid concerns around pricing and the day-ahead market clearing time. While not considering all transmission constraints in the deployment scenarios may lead to some resources being awarded imbalance reserves that are behind constraints, other risks associated with the deployment scenarios can be more carefully monitored and managed if constraints are added incrementally. This tradeoff is acceptable for EDAM go-live as it allows the market to add complexity as market participants gain experience with imbalance reserves. PacifiCorp looks forward to working with the CAISO to ensure the deployment scenarios accurately reflect the transmission constraints PacifiCorp manages today.

PacifiCorp had also asked the CAISO to consider adding in a regional component for allocating the uncertainty requirement to nodes. In past stakeholder meetings, WPTF gave the example of coastal solar being more unpredictable than central valley solar. The CAISO responded to this request by committing to evaluating the need for a regional uncertainty layer in the nodal uncertainty distribution. PacifiCorp has not yet determined if the regional uncertainty layer is needed for the PacifiCorp BAAs but still believes this component is worth studying as it could be an important improvement of the imbalance reserve product.

Capacity eligible to provide imbalance reserves

In the last round of comments, PacifiCorp questioned whether capping an imbalance reserve award to a resource’s 15-minute ramping capability was too restrictive. The CAISO has changed the proposal to now cap the award at a resource’s 30-minute ramping capability. PacifiCorp welcomes this change as it will significantly increase the supply that is eligible to provide imbalance reserves and aid in keeping the cost of the product lower. This change will also give EDAM BAAs more capacity to meet their uncertainty requirements in the EDAM RSE, which is important as EDAM BAAs gain experience with the imbalance reserve product. There has been discussion on the possibility of some of the imbalance reserve requirement being a 30-minute product while the rest is an hourly product procured in RUC. At this time, PacifiCorp is most comfortable starting with a 30-minute product procured in IFM only. If, after gaining experience with this product, it is found that there was a need for an hourly capacity product, PacifiCorp would be willing to engage in a stakeholder process to design it.

Imbalance Reserve Demand Curve

Before the Draft Revised Final Proposal, there had not been much discussion on how the imbalance reserve demand curve would be structured. PacifiCorp appreciates the further consideration by stakeholders and the CAISO on this design feature. PacifiCorp is supportive of the changes made to the demand curve in the addendum released on April 19th.  Starting the EDAM with a demand curve that has an administrative ceiling capped at $55/MWh and an avoidance cost of $247/MWh makes sense. This will keep the costs of the product lower, thereby decreasing risks, as the market gains experience with imbalance reserves. PacifiCorp also appreciates the CAISO getting rid of using the hybrid approach for the CAISO BAA only. The implications for having the hybrid design were not well understood and PacifiCorp believes it is prudent that each EDAM BAA has a demand curve structured in the same way. This parity simplifies the imbalance reserve product and will lead to clearer market outcomes and signals. PacifiCorp asks the CAISO to include the full demand curve structure in the Final Proposal. At this point, it is unclear the price the demand curve will start relaxing the imbalance reserve procurement and how many steps there will be between 100% procurement and 0% procurement.  Any simple examples that show how the demand curve is formed using a hypothetical uncertainty requirement would also be helpful.

Tunable Parameters

In the last round of comments, PacifiCorp asked the CAISO to consider using tunable parameters that could be used to improve the imbalance reserve product as the market gains experience. The CAISO responded to this request by agreeing to flexibly apply constraints in the deployment scenarios and to allocate a tunable percentage of the uncertainty requirement in the deployment scenarios. The constraints and allocation percentage will be studied by the CAISO during the software testing phase. It is PacifiCorp’s understanding that the CAISO will provide analysis during the testing phase on how the market is functioning under varying conditions. PacifiCorp supports the flexibility that the CAISO has included in the design and believes it will be useful for DAME implementation. The CAISO and stakeholders will need to develop clear rules for when the parameters can be changed and on the conditions that will lead to changes being made. However, having ‘levers’ that can be used to proactively manage the risks associated with the imbalance reserve product will be valuable as market participants gain experience.

Market Clearing Time

Stakeholders have expressed concern with the day-ahead market being able to clear by its dedicated publishing time of 1pm. PacifiCorp understands that there is not a way to test how long the day-ahead market will clear until the necessary technology is developed. A suggestion was brought forth during one of the stakeholder technical workshops that the clearing time may need to be pushed back to 2pm.  PacifiCorp does not support this change.  As stated in previous EDAM comments a later clearing time adds complexity to PacifiCorp’s day-ahead activities and should be avoided. There was another suggestion to move up the deadline for submitting day-ahead market schedules to the market at 9am rather than 10am. PacifiCorp is in favor of starting the market processes earlier, if necessary, as most schedules will be locked in before that time.



PacifiCorp is pleased with the improvements made to the DAME initiative since it was initially delayed. PacifiCorp believes the imbalance reserve product now comes with less risk for market participants. The inclusion of flexible design features is also a major improvement. It is inevitable that the imbalance reserve product will be changed in the future, so flexible features allow stakeholders to optimize the imbalance reserve product as more experience is gained. PacifiCorp asks the CAISO to clearly articulate how, and when, the tunable design parameters, such as the transmission constraints and uncertainty allocation percentage used in the deployments, will be set. While PacifiCorp supports the flexibility embedded in the imbalance reserve product, there needs to be clear guidelines and processes to using this flexibility so that market signals and outcomes are consistent and understandable by market participants. PacifiCorp also asks the CAISO to perform analysis on the performance of the imbalance reserve product during the testing phase. There will be a lot to learn during the testing phase, so stakeholders should be informed of how the tunable parameters would potentially affect market outcomes. PacifiCorp also believes the CAISO should be willing to take stakeholder feedback in response to the analysis from the testing phase, specifically regarding which constraints are going to be enforced in the deployment scenarios.  While there remains work to be done to deliver the proposal to the WEIM Governing Body and CAISO Board in May, PacifiCorp believes stakeholders have designed a product that will provide value to the EDAM and commends all that have contributed to the DAME initiative.  

Submitted 04/25/2023, 03:34 pm


Powerex Trade Policy Team (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

Powerex submits the following comments on the CAISO’s April 6, 2023 Day-Ahead Market Enhancements Draft Revised Final Proposal (“Proposal”), the April 19 Addendum, and the associated public meetings and workshops.

CAISO staff have clearly laid out the need for improvements to the Day-Ahead Market to ensure the safe and reliable operation of the grid in real-time, support more efficient price formation, and reduce the need for the large and growing manual operator interventions that continue to distort outcomes and undermine transparency. While Powerex believes that the CAISO’s recent DAME proposals fall well short of the comprehensive enhancements necessary to fully address these challenges, Powerex has nevertheless been generally supportive of the CAISO defining and procuring several new day-ahead products as an incremental improvement over the status quo.

A significant element of the CAISO’s Proposal was to define the conditions under which Imbalance Reserve products would not be fully procured. The April 6 Proposal specified the use of a hybrid approach for the CAISO BAA, consisting of a demand curve and a high penalty price. This hybrid proposal was explained in the April 6 Proposal and discussed with stakeholders at the April 7 workshop. On April 19—the day prior to the original deadline for comments on the Proposal—the CAISO published an Addendum that scrapped the hybrid approach. In its place, the Addendum appears to propose applying a blanket $55/MW price as both an offer cap and penalty price for procuring Imbalance Reserve.

The Addendum does not provide justification for the change; it only alludes to “stakeholder feedback” and asserts, without supporting analysis, that the hybrid proposal “could lead to high prices that exceed the operational benefit of the product.” The Addendum’s explanation is also unclear, stating both that “the avoidance cost of imbalance reserves will be set to $247/MWh” but also that “no steps of the demand curve will exceed the administrative ceiling of $55/MWh for the imbalance reserve product.” The CAISO has not provided any opportunity for stakeholders to ask questions on the Addendum’s new proposal, let alone to evaluate and provide feedback on the substance of the proposal.

Beyond Powerex’s concerns with the specific changes in the Addendum, the CAISO’s unilateral and last-minute re-design of a significant aspect of the DAME Proposal highlights the challenges with its approach to stakeholder engagement. For over five years, stakeholders have dedicated extensive staff resources to evaluating DAME proposals, suggesting modifications, and collaborating on technical analysis. Despite that stakeholder effort, CAISO staff retain exclusive and unilateral discretion to determine which views will be reflected in the final proposal. Powerex believes that inclusive and representative governance in the context of a multi-state day-ahead and real-time organized market requires stakeholders have a more meaningful role in making the key market design and policy decisions that are brought forward to the EIM Governing Body and the CAISO Board of Governors for approval.

Public Generating Pool
Submitted 04/24/2023, 04:54 pm


Mary Wiencke (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

The Public Generating Pool (PGP) appreciates the opportunity to comment on the DAME Draft Revised Final Proposal posted April 6, 2023 and the Addendum – Imbalance Reserve Demand Curve posted on April 19, 2023.

Overall, PGP supports the proposal and finds that the CAISO has fully demonstrated the need for the imbalance reserve product: 1) imbalances between day-ahead and real-time horizons have increased and are likely to increase with greater penetrations of variable energy resources; 2) the current practice of addressing imbalances through load-biasing and other out-of-market actions by operators is inefficient—it is more appropriate and more efficient to procure imbalance reserves through the market; and 3) imbalance reserves are an important component of the benefits expected from the Extended Day-Ahead Market in terms of both diversity benefits and confidence in transfers.  PGP also supports the extended process that resulted in additional workshops and stakeholder engagement that has resulted in further positive modifications to the proposal. Going forward, as the proposal is implemented, PGP recommends transparent and data-driven assessments of the efficacy of the imbalance reserve product within a regional lens.  Many of the elements of the proposal discussed at length during stakeholder meetings warrant robust testing, transparent modeling, and efforts at continuous improvement.  PGP looks forward to following the process as it evolves and as this important market product is implemented.

With additional comments below, PGP supports the Draft Revised Final Proposal including the Addendum and the next step of submitting the proposal for review by the CAISO Board of Governors and the EIM Governing Body.

While supportive of the overall approach, PGP reiterates the following comments on the Draft Revised Final Proposal:

  • CAISO should maintain the downward imbalance reserve product: PGP recommends that the Revised Final Proposal continue to include a downward IR product. This product is likely important for the future in that as variable generation penetrations grow, there will be a greater need for downward flexibility.  Procuring downward imbalance reserves is preferable, and likely more efficient, than curtailing renewable generation in real-time.  Furthermore, implementing this product now can be done with little risk and price exposure because when there is a surplus of downward flexibility prices should fall to zero or near-zero.
  • PGP supports CAISO’s proposed hybrid approach: the CAISO’s proposal to selectively enforce constraints appears to balance between achieving deliverability and avoiding the risks for overly constraining procurement and driving up prices.  Selectively enforcing constraints can hopefully avoid negative unintended consequences and also allow for gradual implementation and monitoring for unexpected outcomes. Though supportive of selectively enforcing constraints, PGP does recommend measures be put in place to ensure transparency of how CAISO is enforcing constraints – which should be based on a stable set of enforced constraints with defined criteria, notification, and rationale. In addition, the CAISO should conduct and provide information with after-the-fact assessments of the performance of the product, including any deliverability issues.
  • Lowering the effective price caps and demand curve may have unintended consequences: while PGP supports the overall proposal and recognizes that compromises are necessary to resolve outstanding concerns, including those of the MSC and DMM, PGP notes that the Addendum proposes to lower the effective price cap and all steps in the demand curve, a relatively material change from the proposal, with comparatively little time for stakeholders to weigh in.  Recognizing the challenge of setting appropriate administrative prices, it is possible that lowering the prices caps and demand curve in this manner will result in insufficient procurement of imbalance reserve products. It is also possible that the discrepancy between the flexible reserve product and imbalance reserve product pricing structures could produce unintended consequences e.g., a higher priced demand curve in real-time could incentivize potential suppliers to offer in real-time as opposed to day-ahead.  PGP also recognizes that setting the demand curve too high can result in over-procurement of the imbalance reserve product and that administrative pricing is inherently challenging.  Therefore, PGP supports moving forward with this proposal but recommends that the CAISO report on the performance of the imbalance reserve product over time including the frequency with which the demand curve sets the price and any targeted volumes that were not procured. 

Public Power Council
Submitted 04/24/2023, 12:06 pm


Michael Linn (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

The Public Power Council[1] (PPC) appreciates the opportunity to provide comments on the Day-Ahead Market Enhancements Draft Revised Final Proposal.  PPC appreciates the opportunity CAISO has provided for additional discussion and the extensive dialogue between CAISO staff and stakeholders.  The stakeholder workshops have provided valuable dialogue on the trade-offs of different approaches to DAME. 

Need for and Scope of Day-Ahead Market Enhancements

PPC remains very supportive of CAISO’s efforts to enhance the day-ahead market.  PPC strongly supports both the creation of new imbalance reserve products and modifications to the Residual Unit Commitment (RUC) to allow procurement of downward capacity.  PPC believes the Day-Ahead Market Enhancements will create benefits for both load and suppliers through increased market efficiency and by providing a market-based mechanism and price for flexible resources to provide flexible capacity.  PPC believes the Day-Ahead Market Enhancements are a positive step towards reducing operator out of market actions.

Demand Curve Addendum

PPC has concerns about the magnitude of changes to the Imbalance Reserve demand curve proposed in the addendum to the Revised Final Proposal.  The changes outlined in the addendum are significant and the timing of the addendum did not provide stakeholders the ability to discuss the change to the proprosal.  PPC is concerned the $55/MWh cap is overly conservative and will undermine the benefits of the proposed imbalance reserve products.  CAISO states the $55/MWh represents a high-percentile replacement cost of spinning reserves.  However, the $55/MWh appears to be a single value that does not consider how the replacement value may change across the hours of the day.


The chart above shows the 97.5% and 99% of Day-Ahead Market spinning reserve prices during 2021-2022 by operating hour.  The data shows the high percentile price of spinning reserves during the evening peak are as much as 3 to 6 times higher than the $55/MWh.  PPC believes the $55/MWh ceiling is far too conservative during the evening peak – when historic operator load bias has been the highest – and will discourage participants from offering imbalance reserves.  By not adequately compensating resources for the market value they provide in reducing operator out-of-market actions and not providing a clear market based price and product for flexible capacity CAISO is potentially undermining the objectives of creating imbalance reserves in the first place. 

Constraint Enforcement Flexibility and IR Deployment Tunability

PPC generally supports CAISO’s proposal to implement functionality to enable control over the types of constraints to enforce and the specific constraints to be enforced in the imbalance deployment scenarios.  PPC also generally supports implementation of a tunable parameter to control the proportion of imbalance reserve awards deployed in the deployment scenarios.  PPC believes this framework reasonably balances stakeholder concerns and provides the ability of CAISO to ensure deliverability of reserves while having the ability to quickly mitigate unforeseen issues. 

The application of these constraints and the IR deployment tunability parameter will have the ability to significantly impact a wide range of market outcomes.  PPC encourages CAISO to miniminize the use of these tools to the greatest extent possible when managing computational complexity and unintended outcomes.  PPC also encourages CAISO establish transparent mechanisms to communicate how and why these tools are being used and what the market impacts are.  PPC believes changes to the relaxed constraints and deliverability parameter should be infrequent and communicated to market participants well before being implemented.  We look forward to additional information from the CAISO on how it will make this process transparent for stakeholders.


[1] PPC members are statutory preference customers of the Bonneville Power Administration (BPA) and represent over 90 percent of BPA’s Tier 1 sales.  Overall, Northwest public power is the largest purchaser of BPA’s power products and services and is among the largest purchasers of BPA’s transmission products and services, funding nearly 70 percent of the agency’s total power and transmission costs.


Rev Renewables
Submitted 04/24/2023, 04:00 pm


Renae Steichen (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

REV Renewables (REV) appreciates CAISO’s efforts to increase stakeholder discussion on DAME proposal revisions in the past few months and to respond to stakeholder concerns. REV continues to support the need for a new Imbalance Reserve (IR) product, particularly as it can reduce the manual out-of-market actions CAISO takes today to increase supply through the residual unit commitment (RUC) process, which can lead to inefficient market outcomes. However, REV still has concerns with the latest proposal and addendum, and it seems the proposal is being rushed to a conclusion due to a goal deadline rather than as a result of rigorous analysis that honed in on a solution. REV’s comments on the draft revised final proposal and addendum are below.


  • CAISO’s proposals to have flexibility in defining constraints for deployment scenarios and a tunable parameter for IR flows introduce uncertainty for market participants. REV appreciates that CAISO is proposing this flexibility to not overly restrict the IR market upon introduction. However, these opportunities for manual intervention by operators also makes it less predictable for stakeholders to understand the market dynamics and outcomes. It is unclear whether this complexity will actually lead to better outcomes. Additionally, a zonal approach (vs. nodal) could better enable this flexibility in a more predictable manner. If CAISO moves forward with this nodal approach with “flexibility”, it must commit to being transparent in what manual actions it takes and why. For example, at a minimum this should be reported as part of the quarterly Market Performance and Planning Forum.
  • The proposed IR administrative price cap could lead to inefficient market outcomes. CAISO’s recently released addendum sets a low $55/MWh administrative cap on IR awards, with no opportunity to increase with penalty prices for days with higher needs. However, the only basis for this dollar amount is based on the rough analysis for default mitigation awards set to a high percentile replacement cost of spinning reserves. This strict cap level should be based on more analysis, or at minimum be open to stakeholder discussion, before implementing. CAISO acknowledges that this cap could lead to inefficient market outcomes and the importance of monitoring[1], but it leads to the question of why CAISO chose to set this low cap instead of the previously discussed $247/MWh. If CAISO does not conduct and share further analysis, REV proposes the cap remain at $247/MWh in order to have better market co-optimization against other products (such as ancillary services) and less out-of-merit IR awards. Appropriate market price signals are a critical part of an efficient market, and stifling that signal could distort the IR market.
    • If CAISO moves forward with this IR administrative cap, REV agrees that this obviates the need for local market power mitigation. REV does not oppose CAISO implementing the functionality for market power mitigation at this time. However, if CAISO adjusts the administrative cap price, then the mitigation tool should be reviewed at that time as well to determine whether adjustments should be made.
  • CAISO should clarify that after the three-year opt-in transitional true-up mechanism, the issue will be handled directly between RA buyers and sellers. As stated in previous comments, REV requests that CAISO clarify that IR is a new product and not a RUC successor product that would be automatically subject to RA capacity settlement. REV supports an optional true-up mechanism for those LSEs and resources that bilaterally determine their contracts are subject to the true-up IR settlement. However, CAISO should clarify that after the three-year transition, this issue will be resolved directly between the RA buyers and sellers.
  • REV is concerned about inconsistencies across storage calculations in CAISO’s models and supports CESA’s proposal for day-ahead state of charge (SOC) equations. While REV supports CAISO adding functionality to include IR awards in SOC equations, REV is concerned about the inconsistent use of multipliers and parameters across different equations. CESA’s proposal for the SOC equation would provide a better starting point for storage resources and provide more predictability for managing SOC.
    • At a minimum, CAISO should commit to transparency in what multipliers are used, and establishing a process to monitor and update the multipliers to better reflect reality. CAISO should also provide details on how the different formulae will work together, and verify that different multipliers are necessary.
  • REV agrees that storage should be allowed to participate in the RUC process. As long as the SOC is feasible for IFM awards and RUC, storage should be allowed to receive RUC awards. As storage becomes an increasing portion of the CAISO resource portfolio, it is critical for storage to be included in RUC so that CAISO is not overscheduling resources due to an incorrect RUC infeasibility. Storage resources that are Resource Adequacy capacity (nearly all in CAISO today) have a must offer obligation and will be participating in the real-time market, and this should be factored in to CAISO’s resource availability models.
    • Additionally, the minimum state of charge (MSOC) constraint trigger is tied to a RUC infeasibility. It is critical for summer 2023 to have storage included in the RUC process to ensure proper MSOC implementation. If that timing is not feasible, CAISO operators should manually identify whether, if storage was included in RUC whether there would actually be an infeasibility (and therefore the MSOC would not actually need to be triggered).


[1] Addendum page 3 – “However, the ISO emphasizes the importance of closely monitoring the DAME/EDAM market to ensure that the demand curve cap does not unintentionally stifle market efficiency or suppress price signals that are essential for maintaining system reliability.  As the market matures and more operational experience is gained, it will be crucial to periodically review and adjust the demand curves to better reflect the true value of imbalance reserves and the associated scarcity conditions.”

San Diego Gas & Electric
Submitted 04/24/2023, 01:17 pm


Alan Meck (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

SDG&E appreciates the opportunity to provide its comments on the Day-Ahead Market Enhancements (DAME) Draft Revised Final Proposal.


Procurement of Imbalance Reserves


When CAISO reopened the DAME initiative, CAISO and stakeholders put forward three different ways to procure Imbalance Reserves (IR): nodal, zonal, and in the Residual Unit Commitment (RUC) process. Each one solves some problems and creates others.


SDG&E supports the zonal solution for the reasons laid out below.




The CAISO put forward the nodal solution noting that its experience with the Flexible Ramping Product (FRP) has shown that deliverability is a significant concern. FRP would often procure resources that were transmission constrained, which increased costs and also reliability concerns. The nodal solution, therefore, proposes to solve this problem by procuring IR on a nodal level and including the potential flows of energy, if called, into the market model in order to reserve the transmission needed.


However, this solution comes with some potential problems. One potential issue is the inability to forecast uncertainty accurately on a nodal level. Uncertainty could be better forecasted on a zonal level.


Another problem with the nodal solution is congestion. Suppose two generators, one at point A and another at point B, where Gen A is $30/MWh and Gen B is $50/MWh. The transfer limit between A and B is 50 MW, and the load at point B is 50 MW. In a world without IR, Gen A would be scheduled to transfer 50 MW to B and the price at both A and B would be $30/MWh (i.e. no congestion). But when IR is added to the solution, suppose that point B has 10 MW of net load uncertainty. Now Gen A is scheduled for 40 MW of energy, 10 MW of IR, and Gen B has to be scheduled for 10 MW of energy. Now the price at A is $30/MWh and at B it is $50/MWh. The inclusion of IR thus creates congestion between A and B due to the fact that IR is being co-optimized with energy schedules.


This has the potential to exacerbate problems that CAISO has experienced in the CRR market. In a perfect market, a CRR that is expected to generate $1,000 in revenue would sell for $1,000 and the CRR would be funded by its own sale. But the CRR market is not perfect and when there are CRR revenue insufficiencies, it gets charged to metered demand through the Real Time Congestion Imbalance Offset account (RTCIO). The problem is that these CRR revenue insufficiencies are structurally built in because most of the would-be buyers in the CRR auctions are regulated by the California Public Utilities Commission (CPUC), which means that LSEs such as SDG&E do not speculate on CRRs due to regulatory risk. As a result, the CRR auction market is not a competitive market and CRR revenue insufficiencies occur regularly.


Thus, procuring IR nodally has the potential to significantly increase congestion in the energy market, which could further drive CRR revenue insufficiencies that will be paid for by metered demand.




The Western Power Trading Forum (WPTF) argued that it might be better to procure IR on a zonal basis, the way that Ancillary Services (AS) are procured. They propose to continue to co-optimize IR with energy schedules within the Integrated Forward Market (IFM). The benefits and drawbacks of the zonal solution are largely the reverse of the nodal solution. It purports to forecast uncertainty better and it can mitigate the congestion issues, but it might run into deliverability issues.




Southern California Edison (SCE) alternatively proposed that IR be moved into RUC, believing that the congestion/CRR issues and overall costs could be very high and therefore RUC might better solve these problems.


But the RUC proposal does not solve the original problem that CAISO set out to solve, namely that operators are currently having to use load biasing in RUC in order to procure flexible resources in the Day-Ahead (DA) timeframe. The problem is that RUC does not target flexible resources, it only considers cost. So if CAISO needs 50 MW of flexible resources in the DA timeframe, but the next cheapest units in RUC are 20 MWs of non-flexible resources, then operators will have to load bias 70 MW in order to get the 50 MWs of flexible resources needed.


After considering all three of these approaches, as well as stakeholder feedback, the DAME Draft Revised Final Proposal continues to propose nodal procurement of IR. SDG&E did not submit initial comments while it continued to weigh all three options, and now supports the zonal solution. It is a market-based solution that solves the original problem statement that CAISO began with, significantly mitigates the potential congestion/CRR cost issues, and SDG&E found WPTF’s analysis convincing that zonal procurement of AS has experienced few deliverability issues. All things considered, the zonal approach seems to be a more elegant solution to all of the issues that need to be addressed.


Imbalance Reserves Demand Curve


SDG&E appreciates CAISO’s Addendum to the DAME Draft Revised Final Proposal wherein it significantly revises down the demand curve for IR. This will hopefully mitigate the cost concerns that SDG&E had with the initial DAME Draft Revised Final Proposal. SDG&E supports the Addendum to significantly reduce the demand curve.


Eligibility to Provide Imbalance Reserves


CAISO proposes to allow resources to bid up to their 30-minute ramping capability.[1] This is a move in the right direction, but CAISO should allow resources to participate up to their 1-hour ramping capability. Our flexible resources are rated based on their 1-hour ramping capability. By restricting the pool of resources for IR to the 30-minute ramping capability standard, CAISO is effectively cutting the IR pool of resources down by as much as 50%. This has the potential to increase costs substantially. SDG&E recommends CAISO alter the proposal to award IR according to each resources’ 1-hour ramping capability.


[1] Day-Ahead Market Enhancements Draft Revised Final Proposal p. 32

Six Cities
Submitted 04/24/2023, 05:05 pm

Submitted on behalf of
Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, CA


Margaret McNaul (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

The Six Cities continue to acknowledge the CAISO’s effort to address remaining stakeholder concerns regarding the previously-published Final Proposal.  As noted in the Six Cities’ post-workshop comments, the CAISO has dedicated substantial effort to refining elements of the DAME proposal, and this has been productive.  However, the Six Cities remain concerned that the continuing evolution of the DAME proposal, particularly with respect to the latest set of revisions to the design of the imbalance reserve product (“IRP”) and, specifically, the methodology by which the CAISO’s IRP requirements will be procured (including the modifications in the April 19, 2023 Addendum), requires additional time to assess and consider.  There does not appear to be sufficient time left in this initiative process for thoughtful consideration of and further revision to the design changes to the IRP for the CAISO balancing authority area (“BAA”).  The Six Cities understand the interdependencies with the Extended Day Ahead Market (“EDAM”) and agree that there is a need to move forward expeditiously. It is equally important, however, to ensure that the CAISO and stakeholders, particularly within the CAISO BAA, since CAISO load-serving entities will be impacted most directly by the design of IRP for the CAISO BAA, have the opportunity to understand, evaluate, and propose changes to the IRP design.  There simply isn’t enough time to between now and the May Board of Governors meeting to fine-tune the CAISO BAA design elements of the IRP and assure CAISO LSEs that they will not face undue reliability risks or excessive costs as a result of the current proposal.  The Six Cities encourage the CAISO to assess if there is a way to extend the schedule for the DAME initiative or discrete elements of the DAME initiative, such as CAISO-BAA implementation issues, to accommodate more time.  At a minimum, the Six Cities request that the CAISO schedule a stakeholder meeting focused on the changes included in the Addendum between now and the May Board of Governors/EIM Governing Body meetings. 

The Six Cities focus their comments below on elements of the proposal that have changed in the Draft Revised Final Proposal, as revised in the April 19th Addendum:

  • Imbalance Reserve Demand Curve: The Six Cities support the changes to the approach to the CAISO’s IRP procurement that are included in the April 19th Addendum, but have questions and potential concerns regarding the newly-proposed approach.  First, the Six Cities request further explanation regarding the CAISO’s apparent conclusion that CAISO BAA exposure to unpredictable export volumes is more limited based on the updated RUC structure in the Draft Revised Final Proposal.  It would be helpful to have more information about the revised RUC elements of the CAISO’s proposal and the interaction with the redesigned IRP elements in order to fully evaluate this change.  Second, the description in the Addendum regarding the avoidance cost of IRP (set at $247/MWh) and the $55/MWh administrative ceiling would benefit from additional explanation of how these elements will interact with one another.  Third, without stating a firm position on the removal of market power mitigation for the IRP at this time, the Six Cities ask whether the CAISO considered reducing the mitigated price in the market power mitigation program.  Fourth, the implications of not using the IRP demand curve in the EDAM resource sufficiency evaluation (“RSE”) and applying penalties to IR requirement relaxation require further explanation and discussion.  The Six Cities would like to better understand the implications of relaxation of IRP procurement at a different penalty price than will be used in the EDAM RSE, and how the CAISO will ensure that it is not unduly exposed to RSE failures in EDAM due to the difference in treatment of the IRP.  Finally, as explained above, the topics addressed in the Addendum would benefit from an additional stakeholder meeting.  
  • Changes to Storage Resources:  The Six Cities have not thus far identified specific concerns with respect to the revised proposals relating to storage resources.  With that said, the Six Cities note concerns raised by the California Energy Storage Alliance and other stakeholders during the April 17th workshop relating to the potential inconsistencies between the various approaches to establishing and/or constraining storage state-of-charge in order to address concerns regarding resource availability.  The CAISO and stakeholders would benefit from continued discussions, which could occur in a future stakeholder process dedicated to storage issues, regarding state of charge management.  As the CAISO’s policies and market participation rules for storage resources continue to evolve, there may be a need to refine the approaches identified here. 
  • Measures to Accommodate Long-Term Contracts:  The Six Cities appreciate the CAISO’s continuing effort to acknowledge the concerns of CAISO LSEs regarding the potential for overlap between resource adequacy (“RA”) obligations under existing RA agreements and the IRP and reliability capacity product included in the DAME proposal.  The Six Cities strongly support the CAISO’s interim proposal to work with RA contract parties to implement a transitional “true up” approach for settling revenues associated with these products when there is overlap with RA obligations.  The Six Cities also support the CAISO’s commitment to provide parties with information to enable bilateral settlement of these revenues when appropriate. 
  • Collection of Congestion Rent on Imbalance Reserve Flows:  Based on the description in the Draft Revised Final Proposal and discussion in the April 7th workshop, the Six Cities support, on a preliminary basis, the CAISO’s proposal to collect congestion rents where IRP deployment scenarios trigger transmission constraints.  However, the Six Cities request that the CAISO provide examples illustrating how the proposed process would be applied.
  • Establishment of Tunable Parameters for IRP Deployment Scenarios:  The Six Cities encourage further evaluation of the CAISO’s proposals to allow flexibility to define what constraints to enforce in IRP deployment scenarios and implementation of a tunable parameter for the proportion of IRP awards deployed.  While appealing in concept, further stakeholder discussion is necessary to support definition and application of such parameters.

Southern California Edison
Submitted 04/24/2023, 03:37 pm


Aditya Chauhan (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

see attached

The Energy Authority
Submitted 04/24/2023, 04:05 pm


Dan Williams (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

Comments of The Energy Authority on the CAISO DAME Revised Draft Final Proposal, including the Imbalance Reserve Demand Curve Addendum posted April 19, 2023.

The Energy Authority (TEA) is a public power-owned, nonprofit corporation that as a national portfolio management company, evaluates challenges, manages risks, and executes solutions to help its clients maximize the value of their assets and respond competitively in the changing energy markets. TEA partners with over 60 public power clients, managing approximately 30,000 MW of peak load and 24,000 MW of generation in North America’s organized and bilateral wholesale energy markets. TEA’s Western Interconnect partners are directly engaged in and impacted by the CAISO’s existing and evolving day-ahead and real-time energy markets.

TEA applauds the CAISO’s efforts to develop innovative market solutions intended to increase the efficiency and reliability of its existing market framework as it navigates the changing dynamics of its grid and seeks to integrate a future resource pool fundamentally different than those contemplated when its current market framework was installed. TEA supports the CAISO adjusting existing processes and developing new "in-market" solutions that provide incentives for resources and loads to participate in the CAISO’s markets in a way that maximizes market efficiency and reliability. TEA agrees that it is imperative that the CAISO’s markets and its operations adapt in their fundamental design structure to meet the realities of the changing grid.

TEA is concerned however that the CAISO is not yet at a point with the DAME initiative where stakeholders can be confident that the enhancements proposed will meet the above objectives and lead to the desired outcomes. TEA agrees with other stakeholders that the level of impact significant changes to the Day-Ahead Market will have warrants a high degree of scrutiny and testing prior to adoption. TEA believes the significant number of last-minute changes in the DAME Revised Draft Final Proposal (Proposal), including those in the Addendum published after the final DAME stakeholder meeting, have precluded adequate vetting by stakeholders or adequate stress-testing by CAISO staff. TEA is also concerned that moving forward with the Proposal at this time risks constraining available solutions or prejudging outcomes in other important CAISO initiatives, such as the Price Formation Enhancements, Resource Adequacy Enhancements, and Energy Storage Enhancements initiatives, among others.

TEA therefore recommends the CAISO revisit its DAME initiative timeline and hold additional stakeholder workshops to: (1) explore further and test the elements of the Proposal that have seen multiple changes over the past 3-6 months, (2) consider alternative stakeholder proposals where prudent, and (3) assess fully the interdependencies between the changes proposed in DAME and potential policy directions in other high-priority current or near-future CAISO workstreams.

TEA appreciates the opportunity to provide comments and looks forward to continuing dialogue with the CAISO and other stakeholders regarding this important initiative.

Vistra Corp.
Submitted 04/24/2023, 04:56 pm


Cathleen Colbert (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

Vistra appreciates the CAISO leadership team making the decision to defer the Day-Ahead Market Enhancements (DAME) effort from the February 1, 2023 joint Western Energy Imbalance Market Governing Body and California ISO Board of Directors meeting until May to allow for additional development. This deferral has allowed for roughly three months of additional stakeholder discussions. These discussions have provided value in bringing greater understanding between the CAISO and stakeholders on why specific proposals are being advanced and why certain stakeholders hold the views they do.

It is our observation that the CAISO’s focus has been trying to address specific concerns that certain stakeholders have with its proposed design. We had hoped that CAISO would have taken a broad-based holistic approach to identifying and supporting issues to be addressed, with the goal of identifying solutions that directly address these issues. In our comments, Vistra will zoom out to provide feedback on the DAME proposal as a package rather than to comment on nuances in this proposal.

Perspectives on imbalance reserves

Why is the specific design of the proposed imbalance reserve product so important?

At a high level, an integrated forward market needs to send price signals that are clear, effectively incorporated into forward markets, and solve for grid needs efficiently. To be well-functioning, the Integrated Forward Market (IFM) needs to rationally price energy, ancillary services, imbalance reserves, and backstop capacity services to send the right price signals for investment and performance. It is essential that any design proposed does not muddy locational marginal prices or reduce price transparency, because that would reduce confidence in the day-ahead market. Eroding confidence in the day-ahead clearing prices’ ability to incent locational performance negatively impacts forward investment decisions. It also impacts the ability to maintain the economics of prior investment decisions that factored in energy & ancillary service prices. Can the CAISO’s design that uses deployment scenarios and enforces constraints with an exceptional amount of discretion produce clearing prices that are certain and meaningful enough to inform rational forward market prices that facilitate prudent forward investments?

The California Public Utility Commission is contemplating retiring flexible Resource Adequacy (RA) products under Slice of Day (SOD) framework, the recent RA Reform Track Decision (D.23-04-010) stated that, “The Commission will coordinate with CAISO on the future removal of the flexible RA requirements for the SOD framework.”[1] Consequently, the day-ahead market must serve as the vehicle to incentivize flexibility in the California Balancing Authority Area’s (BAA) fleet. The day-ahead flexibility product will need to provide compensation for resources commensurate with providing flexible Resource Adequacy (RA) products under the California RA program, or else it could undermine incentives to provide flexible capacity. Undermining or devaluing flexibility is not in the best interest of reliability given the variability of the evolving grid.

We believe the CAISO does not intend to undermine flexibility signals, but that it has been narrowly focused on a specific set of concerns without due consideration to the impacts to market participants’ long-term decisions. What are those specific set of concerns?

Our understanding is that CAISO is attempting to address the following concerns it has with its Integrated Forward Market (IFM) that causes its operators to lean on RUC to mitigate today. CAISO has found the following limitations with IFM:

  • IFM could have awarded more export schedules at the CAISO intertie scheduling points than CAISO believes is reliable to support because largely driven by lower bid-in demand than the operator adjusted RUC target.
  • IFM could have uncleared 15-minute import offers that could awarded if there is an additional requirement to produce import awards above what the bid-in demand would otherwise allow.
  • IFM could have uncleared non-Resource Adequacy Resources that are 15-minute ramp capable that would have cleared if there was the additional requirement above what the bid-in demand would otherwise allow.
  • IFM could have uncommitted long start resources that only day-ahead market can commit to provide more real-time 15-minute ramp capability above what the bid-in demand would otherwise allow.

Today, CAISO BAA operator’s make out-of-market adjustments to the Residual Unit Commitment load forecast to ensure either sufficient capacity to meet forecasted load or sufficient flexibility to meet net load uncertainty to address these concerns by increasing the RUC target such that RUC may (1) reduce low priority IFM exports, (2) increasing net scheduled imports through its reduction of IFM exports, (3) award non-RA resources that the IFM did not clear a must offer obligation, and committing long start resources that the IFM did not commit. The use of operator adjustments to ensure there is sufficient capacity to meet real-time needs, especially on tight days, are not proposed to be impacted by the new imbalance reserves. We understand their intent is to move the portion of the load conformance done for risk of net load uncertainty out of RUC target and into IFM so IFM can solve the four above concerns.

The CAISO’s proposal will not adequately address its concerns because the proposal would:

  • Establish an uncertainty requirement for each BAA after including the diversity benefit and will not include a minimum BAA requirement to address over-crediting. Given CAISO’s share of the transfer capability in EDAM this will result in effectively zero MW CAISO BAA requirements. With a system diversity benefit credit and in the absence of BAA minimum requirements, the resulting uncertainty requirements for each BAA in sum are unlikely to be an accurate view of the EDAM’s flexibility needs or provide operator’s confidence in the solution. The EDAM will set uncertainty requirements only in the areas with limited transfer capability, hence lower diversity benefit credits, where the imbalance reserve offers will be serving this more limited requirement in non-CAISO EDAM BAA with lower transfer capability. Further, the IFM will not result in increasing the amount of net imports awarded, or exports uncleared. Thus, it is unlikely to provide CAISO BAA operators’ sufficient confidence that the IFM will result in enough net imports into the EDAM to ensure enough flexible resources to meet the CAISO BAA’s needs within EDAM.
  • Mitigate and administratively cap prices to no more than $55/MWh in all hours which will disincentivize participation from internal or external EDAM resources not under a California Resource Adequacy obligation because energy awards will be preferable to imbalance reserve awards. Without a reasonable ability to reflect the value of flexibility in its offers, resources outside of CAISO/EDAM that do not have a must offer obligation will not be incentivized to participate. The desire to procure additional non-RA resources from outside the EDAM footprint to import into EDAM or to procure additional non-RA resources inside the CAISO footprint is unlikely to materialize given the extent of the mitigation and price suppression proposed.

Stakeholder discussions recently have focused on specific elements of the CAISO’s proposal instead of focusing on the holistic package and whether the package of elements can improve the market relative to what is in place today. Unfortunately given the current proposal, CAISO operators will not only continue to adjust the RUC forecast for concerns with sufficient capacity but will also continue to adjust the RUC forecast for net load uncertainty concerns. We anticipate little to no changes to the RUC forecast adjustments will occur. This leads us to question why CAISO would propose such a large market design change that does not address its raised concerns intra-market but will continue to rely on RUC.

Vistra continues to be concerned with individual elements proposed by CAISO, however we are concerned that focus on tweaking individual elements has caused CAISO and stakeholders to lose sight of the important question of whether this design improves the market or not. We do not think this design is moving the market in a positive direction. The entire package proposed is likely to degrade the quality of the day-ahead market. The following expands more fully on adverse outcomes Vistra is concerned this design would introduce:

  • Nodal design introduces risks that the market will undermine confidence in the locational marginal prices, especially the marginal cost of congestion, without addressing the deliverability challenges between EDAM sub-regions. We are concerned that this debate has lost sight of what problem needs to be solved. The challenges with deliverability in real-time are observed between regions within Western Energy Imbalance Market not between zones within a single BAA.[2] The minimum requirement for Flexible Ramping Product was implemented to address these deliverability concerns, a design element that CAISO has failed to include in this proposal.[3] It appears likely that the CAISO believes it can remove the minimum requirement because it has done so to its real-time market when it implemented nodal Flexible Ramping Product (FRP).[4] The recent data on nodal FRP shows that without a minimum requirement in place the deliverability challenges previously observed appear to be present as the procurement of FRP has largely shifted out of the CAISO BAA to the Northwest.[5] Vistra strongly believes that in a nodal or zonal approach it is essential that either a minimum requirement as previously adopted or the alternate we proposed of setting regional diversity benefits to be included in the BAA uncertainty requirement must be included in the design. The absence of either of these features results in a nodal design that performs more poorly than a zonal design with minimum requirements as demonstrated by initial FRP performance.
  • Design could undermine the integrity of the locational marginal price congestion signals that impact forward investment decisions, which is especially concerning for existing and new storage resources. In areas where the EDAM sets a BAA requirement above zero MW and distributes that requirement internally to that BAA, it will be possible that the marginal cost of congestion for storage locations will be impacted with congestion that may not materialize. For existing storage resources, the CAISO’s design could result in increased congestion narrowing the charge spread that storage resources would receive through its day-ahead participation. If congestion narrows significantly compared to forward projections used to establish its value when contracted, then the CAISO’s market may make storage resources uneconomic because insufficient capital costs would have been recovered in the long-term agreements with the expectation of just and reasonable energy revenues to offset its operations. For new resources, if by narrowing the charge spread that will materialize for storage resources it is likely new storage projects forward capacity costs will increase due to the reduced amount of projected revenues. Given our commitment to developing storage to support clean energy transition, this outcome cannot be supported. We appreciate that the CAISO is proposing exceptional levels of flexibility to address our concerns with “pancaked” or “phantom” congestion arising due to the modeling of imbalance reserves that may or may not materialize, but we question whether the increased uncertainty puts developers into an even less acceptable decision as we would have to base long-term capital decisions on projections of CAISO prices with significant uncertainty. This also introduces a great deal of difficulty in managing the existing storage assets to provide optimal value.
  • Design would introduce increasingly complex and compounding storage state of charge management and limitations to imbalance reserves and regulation awards on storage, which will impact storage’s dispatch assumptions critical to making prudent investment decisions and managing annual operating costs. The CAISO’s storage modeling proposals from both Energy Storage Enhancements and Day-Ahead Market Enhancements will introduce significant uncertainty into how the various state of charge calculations included in various constraints and how the constraints limiting storage awards due to its operating range will change storage dispatch assumptions also critical to forward projections used to determine least cost capacity offers. This challenge also introduces a great deal of difficulty in managing the existing storage assets to provide optimal value. Vistra does not support the CAISO’s proposal including the envelope equations. We urge CAISO to drop its proposal and to adopt California Energy Storage Alliance’s (CESA) proposal submitted in comments and presented on April 17, 2023.[6]
  • Design will not send flexibility price signals commensurate with the need to incentivize flexibility investment decisions, such that with the retirement of flexible RA these resources will lose compensation without sufficient signal commensurate with the retiring product. Mitigating and limiting imbalance reserve price formation to no more than $55/MWh is unlikely to value flexibility strongly enough to incent investment decisions. Without a forward capacity product assuming the retirement of flex Resource Adequacy resources, the imbalance reserve prices will need to be the vehicle to incentivize continued investment and maintenance to maintain highest flexibility capabilities. The CAISO design does not position its market to provide this signal, so will fail to incentivize flexibility.

We believe the CAISO should question whether introducing significant risks to market participants is appropriate if it will not address its concerns, will undermine price transparency and confidence, and will make it more difficult to understand and participate in the day-ahead market.

Perspectives on reliability capacity

Taking a step back from the detailed debates that have recently occurred, Vistra has attempted to seriously explore why CAISO is insistent on redesigning its RUC process. To be fair, Vistra acknowledges that there was a robust problem statement for a reliability capacity product to be designed if it were to be introduced into the IFM as this would have increased efficiencies through co-optimizing it with all other energy and ancillary services. However, this is not the proposal. The proposal is to redesign the existing RUC process to add a downward product and allow RUC to schedule Multi-Stage Generators in RUC at its lowest configuration. Under the revised Final Proposal what problem is CAISO trying to solve?

CAISO states that “reliability capacity is needed in the EDAM to ensure physical supply is committed to cover differences in cleared physical supply and each BAA’s net load forecast.”[7] We have not received an explanation from the CAISO as to why a new product in the RUC process is needed to ensure physical supply is committed to cover differences in cleared physical supply and BAA’s net load forecast. The current RUC process can ensure this outcome as well. This stated issue cannot be the driver of CAISO’s RUC proposal since new products are not needed to address this concern. The CAISO could allow the existing RUC availability offers to support transfers between BAAs.[8]

CAISO has stated they believe changes to RUC to allow California Resource Adequacy resources to offer non-zero RUC offers is needed for EDAM to mitigate the risk that zero dollar per MW RUC capacity from Resource Adequacy resources are not unfairly supporting needs throughout the EDAM. CAISO has not explained the basis for its belief that Resource Adequacy resources can submit non-zero offers into RUC for backstop capacity when RA resources are currently not able to submit non-zero offers into RUC. This stated issue cannot be the driver of changes to RUC either.

CAISO has stated that its operation engineers would like to be able to see which Multi-Stage Generators if their IFM schedule was reduced to its lowest configuration would be the best decommitment to manage congestion identified in RUC. CAISO’s hope is that a downward product will replace exceptional dispatches that CAISO operations issues to MSGs for congestion management observed in RUC. However, Vistra presented at the February 27, 2023 workshop on the need for downward products explaining why the CAISO proposal cannot achieve this goal.[9] The CAISO proposal has never proposed to change the real-time binding configuration logic, in fact the entire proposal is only impacting the day-ahead market. Without changes to the real-time binding configuration logic, operations will still need to issue exceptional dispatches. This change could provide some more information to Operations Engineering. A simpler change to RUC to allow the RUC process to “cut” MSG schedules down to the lowest configuration can also provide more transparency into the most effective MSGs to reduce congestion.

CAISO has not clearly stated another reason or shown analysis supporting a need for a new RUC product to facilitate downward awards. Regardless, Vistra provided analysis on February 27, 2023 showing that downward flexibility is not an issue facing the Western Energy Imbalance Market in either the Fifteen Minute Market or Five Minute Market.[10] Therefore, it is fair to agree there is no downward flexibility need driving the proposal for a new product, likely because the market has sufficient downward capability from the day-ahead cleared schedules that can be reduced.

The only potential use case that appears initially compelling is that the existing RUC process is only an incremental process and as such batteries could not receive a RUC down award to allow it to “charge” to provide downward capacity offsetting excess resource schedules.[11] CAISO proposes functionality to include Non-Generator Resource offers in RUC in its revised Final Proposal however this proposal appears to conform to the limitations of the existing RUC process, since it does not allow RUC to increase the state of charge throughout the operating horizon if downward capacity is needed. The storage rules proposed for RUC appear to confuse the existing RUC with the proposed new products. Again, even the potential use case does not materialize because CAISO’s proposal does not allow for changes to the state of charge from that determined by IFM. What is clear is that changes to RUC are needed today to insert RUC capacity at $0/MW for all RA capacity physically capable of operating. These changes should not be dependent on the success of DAME because the current functionality does not allow for full compliance with the existing Tariff. These changes are also new changes and are not a driver of the proposed new product.

At the end of this analysis, we have arrived at the conclusion that there is no need for holistic changes to RUC in DAME. There appears to be no need for a new RUC product and the uncertainty and compliance risks it would introduce are significant.

[1] Decision on the Phase 2 of the Resource Adequacy Reform Track, Decision 23-04-010, April 7, 2023, Page 179,

[2] “[P]otential for stranded flexible ramping capacity. While this issue can occur in other areas, it is most prominent in the Northwest region, which includes PacifiCorp West, Puget Sound Energy, Portland General Electric, Seattle City Light, and Powerex; this is because of limited transfer capability out of the Northwest region… Figure 2.23 shows the potential for stranded upward flexible ramping capacity in the Northwest during 2021 and highlights how the outcome illustrated in the example interval in Figure 2.22 can persist throughout the year.” Department of Market Monitoring 2021 Annual Report, Page 121-122,

[3] “The minimum requirement is intended to help mitigate some of the issues surrounding procurement of stranded flexible ramping product prior to the implementation of nodal procurement, expected in Fall 2022. The minimum requirement was initially implemented in the 15-minute market only. DMM recommended that the minimum requirement be included in the 5-minute market as an enhancement to improve the effectiveness of the flexible ramping product until nodal procurement implementation.4 The California ISO implemented the 5-minute market minimum requirement on February 16, 2022.” Department of Market Monitoring 2021 Annual Report, Page 8,

[4] Market Performance and Planning Forum, March 16, 2023, Slice 76 - 77,

[5] Id, slide states both “Procurement from CAISO area dropped significantly with introduction of nodal requirement” and “no minimum requirement imposed for CAISO area”.

[6] California Energy Storage Alliance comments submitted on March 30, 2023,; California Energy Storage Alliance presentation on April 17, 2023,

[7] Day-Ahead Market Enhancements Revised Final Proposal, Page 17,

[8] Vistra strongly opposes allowing transfers between BAA in RUC process as described repeatedly in our Extended Day-Ahead Market comments. We are optimistic the CAISO will arrive to this conclusion before implementation.

[9] Vistra presentation at the February 27, 2023 workshop, slides 1-16,

[10] Id.

[11] CAISO Tariff Section states “Non-Generator Resources that do not use Regulation Energy Management shall submit: (A) Economic Bids or Self-Schedules into the IFM for all RA Capacity for all hours of the month the resource is physically capable of operating; and (B) $0/MW RUC Availability Bids for all RA Capacity for all hours of the month the resource is physically capable of operating,” CAISO functionality does not allow storage resources to meet (B) of Section, because its current functionality does not insert RUC capacity offers for RA capacity that does not clear IFM. We fully support CAISO pursuing changes to its functionality to fix the inability of the market functionality to meet section Vistra believes the current proposal could be workable under existing RUC process with the exception that there should not be any envelope equations. CAISO should include the Ancillary Service State of Charge constraint and should include RUC awards in the SOC formulation. Since existing RUC only awards incremental awards, this approach will work as an immediate solution and allow for future refinements as needed.

Wellhead Electric Company, Inc.
Submitted 04/20/2023, 02:36 pm


Grant McDaniel (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

Wellhead appreciates the opportunity to provide comments on the CAISO’s Draft Revised Final Proposal for the Day-ahead Market Enhancements (DAME) policy effort. From the onset of this initiative, the CAISO has been transparent regarding the use of load conformance by operators to help manage real-time uncertainty. However, load conformance has lead to suppressed real-time market prices removing a significant amount of revenues from the market. Thus, Wellhead has been extremely supportive from the beginning of this effort to develop a day-ahead market-based product to address uncertainty that will result in reduced operator actions and more appropriate day-ahead and real-time price formation.

However, Wellhead is extremely concerned that the proposal as reflected in the Draft Revised Final Proposal and further modified through the April 17th workshop and April 19th addendum is far from the original intent of developing a market-based product for the reasons listed below, which are then subsequently expanded upon.

  • The CAISO needs to be clear that the IR is not a successor to RA
  • The $55/MW bid cap is overly restrictive and is a detrimental step backwards to a market based product

The latest proposal now includes an optional settlement tool for both contracting parties to utilize as a means of allocating the revenues from IR among the contracting parties. This late addition seems to suggest that IR is a successor to RA and in three years when the settlement tool is no longer in place that may become the perspective of contracting entities. However, Wellhead does not agree that IR is a successor to RA and we ask that the CAISO be extremely clear in this regard. IR is a capacity product intended to result in more efficient unit commitment coming out of the day-ahead market to better position the fleet to address a variety of real-time conditions that may arise.

The CAISO has now imposed a $55/MW bid cap on the IR products through the addendum issued April 19th with no scheduled stakeholder call. This is a significant change from the bid cap of $247/MW that has been discussed (and remained consistent) since the beginning of the nodal market design discussions. There is no public call to discuss this latest change, and we have only been provided 6 days to submit comments. The newly imposed bid cap is overly restrictive and is a detrimental step backwards from what should, and could be, a valuable day-ahead market based product. A bid cap this low will hinder the ability of the market to efficiently schedule and dispatch the resource fleet as it prohibits the ability of entities to fully reflect their willingness to provide the product, including any opportunity cost. Furthermore, there is no substantial discussion in the paper supporting $55/MW other than that it aligns with the new demand curve cap of $55/MW (which is also a significant change from prior iterations). It remains unclear to Wellhead why the new demand curve cap and bid cap of $55/MW is appropriate as the addendum lacks any detailed explanation, especially given that only DMM suggested a demand curve bid cap below the $247/MW offer curve cap that was previously contemplated.

Submitted 04/24/2023, 01:15 pm

Submitted on behalf of
Western Power Trading Forum


Kallie Wells (

1. Please provide your organization's feedback on the changes made to the Day-Ahead Market Enhancements final proposal:

WPTF appreciates the opportunity to provide comments on the CAISO’s Draft Revised Final Proposal for the Day-ahead Market Enhancements initiative. These comments are also in response to the DAME Storage workshop held on April 17 and the Addendum to the Draft Revised Final Proposal posted on April 19. First, we would like to commend the CAISO for taking the additional time and continuing discussions with stakeholders on what will be a significant overhaul to the existing day-ahead market design that will impact over 90% of cleared transactions. We recognize it was an intense effort and also applaud the other stakeholders that put forth a significant amount of time and resources to contribute to these discussions.

That being said, WPTF still does not believe this policy is ready to seek joint approval from the CAISO Board of Governors and Western Energy Imbalance Market Governing Body, or to be filed at FERC. To be clear, this concern is not solely about the zonal or nodal framework, but the recognition that even this last revision to the policy includes several new market design elements and significant changes from prior iterations. These items have not been properly vetted with stakeholders. The April 7 stakeholder call was used to explain the latest changes to the stakeholder community and did not provide ample time for participants to consider and evaluate the impact the new changes will have on the market ahead of that call.[1] Furthermore, the CAISO continued to make material and substantive changes to the policy through subsequent conversations and addendums that were posted after what was expected to be the final stakeholder call.[2] The only opportunity stakeholders have to respond to these last-minute changes is through these comments, which does not allow sufficient public discussion or any iteration to resolve questions and concerns. Given the changes from the April 7th policy paper to the April 19th addendum, it appears as though even the CAISO is struggling to nail down a robust market design.

Overall, WPTF has the following concerns with the latest proposal making it premature to seek CAISO Board approval:

  • The proposed design will not result in reduced operator biasing of RUC forecast, which was the primary goal for this effort.
  • Several significant details have been left as “to be determined” during implementation efforts that will impact rates, terms, and conditions.
  • Newly introduced constraints for storage resources that stakeholders have not been afforded sufficient time to evaluate for efficient and appropriate interactions with existing constraints and constraints being implemented through other policy efforts.
  • CAISO has not provided support for the need of downward products, despite numerous stakeholder requests for such justification.
  • Two different demand curve designs were proposed within a two-week period both of which have differing and substantial adverse market implications that have yet to be discussed.
  • Newly introduced “lever” the CAISO operators can utilize to at their discretion that essentially allows them to move from a zonal framework to nodal by increasing/decreasing the transmission constraints enforced.
  • Newly introduced “lever” the CAISO operators can utilize at their discretion that essentially dials down or up the price signals resulting from deployment scenarios, which also adversely impacts the ability of entities to effectively hedge through participation in the congestion revenue rights (CRR) market and introduces uncertainty on storage being able to effectively manage their use based on projected charge spreads that are sensitive to observed congestion.
  • The policy continues to combine energy market and capacity market design elements that will be detrimental to the day-ahead market.
  • Newly proposed bid cap on imbalance reserves that will harm efficient participation, most notably for the storage fleet, suppress overall market signals to incentivize flexibility, and potentially create a new reliance on ancillary services products.

As iterated throughout prior comments and during discussions, we are concerned that the FERC risk has not been adequately addressed and thus will put CAISO in a much harder position to implement DAME alongside EDAM in fall 2024 than would be the case if proper time was taken up front to mitigate these risks. WPTF strongly urges the CAISO to consider a more reasonable approach that can be implemented as an initial design that allows for enhancements to be made after gained experience. We understand that the CAISO has included such language within the latest iteration, but it starts with the most complex design and only intends to pull it back if adverse market impacts are identified. Rather than starting with a design that can harm the day-ahead market solution, we urge the CAISO to start on the other end and only add complexity as the more streamlined approach indicates changes are warranted and such changes would provide commensurate benefits. Additionally, taking a chance on the market design and fixing it down the road introduces additional risk not only in the CAISO market but also in forward contracting and resource development, which have long term market efficiency implications.

We appreciate the CAISO holding an additional workshop to continue discussing the storage related elements of the proposal with stakeholders. The last iteration of the paper that was covered on the April 7th call introduced new constraints that warranted further discussion such that stakeholders can understand what the CAISO is proposing and then evaluate the implications. While the additional April 17th workshop did provide for an initial opportunity to do so, it is still unclear to WPTF what exactly the issue is that the CAISO is trying to address with the new “envelope” equations that simply expanding the other constraints in a similar manner as was done in Energy Storage Enhancements (ESE) for regulation doesn’t address. Additionally, the CAISO has been proposing several changes to various storage constraints through several different policy efforts. In this last discussion there was no time provided to walk stakeholders through how these new constraints will interact with (1) existing constraints and (2) the constraints proposed in ESE. Thus, WPTF has the following two requests to be included in the next iteration of the DAME proposal:

  • That the CAISO clearly articulates the issue that expanding the ESE storage constraints to include IR does not address and thus requires these new envelope constraints.
  • That the CAISO provide a complete list of all the storage related constraints that will be applied to storage resources in both the day-ahead and real-time markets reflecting what will ultimately be in the market following implementation of ESE and DAME as currently proposed along with an explanation as to what issue each constraint is addressing. 

Additionally, during the storage workshop the CAISO presented changes to the RUC process that will enable storage resource participation. While we appreciate the CAISO addressing this issue, including it at this point in the policy process provides minimal opportunity for stakeholders to engage in discussions with CAISO. Overall, we view the proposed change as a step forward over the existing treatment of storage resources in RUC under today’s RUC design. However, looking toward to the RUC framework as contemplated in this effort, we are concerned the proposed change does not fully capture the capabilities of storage resources. For example, when a storage resource is awarded RCD, our understanding of the proposed change is that it will then not allow for additional RCU to be awarded in a following hour since the RCD does not change the calculated state-of-charge. Also, it is unclear to WPTF if/how a storage resource’s RCD award will overlap with an IFM energy schedule. Thus, we ask that additional discussions and clarifications are provided such that we can fully evaluate the impact this change will have on storage participation in RUC.

Lastly, WPTF is extremely concerned with the significant and last-minute market design changes that were just posted on April 19, 2023 in an addendum. First, there is no opportunity for stakeholders to ask questions or engage in a public discussion with the CAISO given that these are the last set of comments to be submitted and no call is scheduled. Second, the need for these changes is not adequately justified in the April 19 addendum and the changes seem to run counter to justifications provided for other market design decisions. Third, this will hinder the ability for the market to efficiently and effectively dispatch storage resources, which will be a significant portion of the overall fleet by the time these changes are implemented. Finally, these changes take a substantial step backwards in terms of running a competitive wholesale energy market based on willingness to supply and will likely result in detrimental impacts to the day-ahead market that clears 90% of all transactions.


[1] The Revised Draft Final Proposal was posted during the afternoon on the day prior to the call.

[2] The storage workshop material was posted the day of the call and the CAISO did not hold a stakeholder call to discuss the addendum.

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