Comments on February 27 and March 7-8 workshop discussions

Day-ahead market enhancements

Comment period
Mar 16, 03:00 pm - Mar 30, 05:00 pm
Submitting organizations
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Submitted 03/30/2023, 08:08 pm

Submitted on behalf of
Balancing Authority of Northern California (BANC)


Kevin Smith (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The Balancing Authority of Northern California (BANC) appreciates the opportunity to provide feedback on modifications to the CAISO’s current DAME proposal.  First, BANC commends the CAISO for reopening this process to provide stakeholders with further opportunity to both further examine, and perhaps even refine, the DAME proposal.  While the initial scope of this process was primarily to reexamine whether a zonal procurement model, as had been suggested by some, might provide a more simplified and sufficiently accurate approach to the procurement of imbalance reserves (IRs), it appears to BANC that there are also unintended consequences to that approach.  Furthermore, the zonal model does not align well with the current EDAM design and therefore causes implementation risk.  Moreover, as an entity with six LSEs within its Balancing Authority Area, BANC is always concerned about the ability of suppliers to exercise market power, particularly during the start-up phase of any new market, such as EDAM.  To BANC, while a zonal model may have simplified procurement, it does not address potential market power concerns. Thus, BANC urges that the CAISO retain its original concept of a nodal procurement of IRs, with further consideration of the following:

Robust Pre-Market Testing

Perhaps it goes without saying, but the CAISO should conduct robust pre-market testing of the design and utilize the data from FRP, which should be relatively significant by the time DAME goes into production.  Any design adopted, as discussed further below, should be tunable to address needed corrections manifested during this pre-market testing.

Must Retain Flexibility for Post-Market Startup Adjustment

One key element is for the CAISO to commence DAME with a level of flexibility which allows it to move from a more conservative approach to its constraint enforcement in the deployment scenarios to a more refined approach based on operational experience.  In other words, the CAISO should seek approval of a tunable design that will not require a protracted approval process to make improvements to its constraint application – i.e., from application to active and base constraints to, if needed, a more granular set of constraints.

Does not Overly Restrict IR Product Procurement

Concerns have been raised by the MSC and others that retaining rigidity around the 15-minute ramping requirement is too restrictive.  While BANC understands why this 15-minute requirement was chosen, it may unnecessarily limit the pool of resources capable of providing IR.  This may lead to scarcity and unreasonably higher IR pricing. BANC encourages the CAISO to consider whether there is some reasonable loosening of this constraint (between 30 and 60 minutes) and through observation and market operations, move towards a 15-minute ramping product as the product availability becomes more evident.

Current IR Demand Curve Should be Reconsidered

BANC would support a more conservative approach to the IR demand curve at start-up.  More specifically, procuring to a lower value to avoid over-procurement and market pricing distortions. Currently, the proposal tethers itself to the demand curve used in FRP, but FRP is an energy product in the real time market, where the procurement needs are more clearly understood.  Thus, it appears to be a risk to utilize the same demand curve for IR.  At bottom, this is a very complex subject that will require more discussion and is an example of why having the ability to make parameter adjustments after commencement of the market is a good policy.


SCE put forward a very compelling case for moving the IR procurement from the IFM to the RUC.  However, BANC believes that the value of the co-optimization in the IFM is important and further sets the two products (IR and reliability capacity) apart.  It would appear to BANC that some of the more critical concerns raised by SCE, such as price distortions and inviting higher levels of virtual bidding, can be largely addressed through expanding the pool of qualified IR resources and lowering the IR demand curve. This may ultimately lead to greater RUC procurement or looking at some bifurcation of IR procurement between the IFM and RUC.  But in any case, this is a starting point, and having a tunable DAME will allow certain adjustments to be made as the CAISO and market participants gain more confidence in the IR procurement process.

Distribution of Uncertainty

One area raised by WPTF was how the CAISO proposes to allocate VER uncertainty.  The fact that solar, for example, can have significant variations within the CAISO footprint between the north coast and Central Valley, should merit considering adjustments as to where the uncertainty is allocated. Indeed, if the goal of a nodal procurement is improved granularity, not only for ensuring deliverability, but also to address other material variations impacting IRs, it seems intuitive that this allocation should be done in a manner consistent with these locational variations. BANC agrees that it is very difficult to be precise as to where on the system uncertainty will materialize, but it does believe more discussion around this issue is merited. 

Maintaining the Current Schedule

BANC was supportive of this effort to take more time with DAME and to revisit a zonal versus nodal procurement of IR.  We assumed that there was sufficient time to allow for further discussion while ensuring that this additional DAME process does not impede the expected timelines related to EDAM implementation. This process has already proven itself to be useful, as it has revealed several areas of possible improvement, but it did not reveal the need for a wholesale revisiting of the original design, such as moving from nodal to zonal.  It is BANC’s hope that the CAISO will take this additional time to consider some of the reasonable issues raised by stakeholders and the MSC, which should allow the CAISO to stay on its proposed timeline. 

Bonneville Power Administration
Submitted 03/30/2023, 03:32 pm


Sara Eaton (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The Bonneville Power Administration (Bonneville)[1] appreciates the additional opportunity to comment on the DAME final proposal. As discussions around regionalization expand, it is more critical than ever for 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.   

The discussion at recent DAME workshops centered on potential complications associated with CAISO’s proposal for nodal procurement methodology of imbalance reserves, as consistent with the flexible ramping product, rather than a zonal procurement methodology, consistent with other ancillary service products. Multiple stakeholders, including CAISO, shared potential attributes of a zonal procurement proposal, but a formal alternate proposal for zonal procurement still does not exist, preventing a comparison between the two options on their merits. 

CAISO’s high-level description of a zonal alternative essentially aggregates individual nodes into zones for procurement and market clearing, but maintains a nodal need calculation to facilitate system operators’ ability to deliver reserves over constrained paths. This approach is encouraging to Bonneville because it appears to replace nodal market power mitigation with more realistic zonal market power mitigation, which should enable a greater quantity of competitive supply.  Bonneville has stated in previous comments that encouraging competition is the best way to address market power, rather than dis-incenting supply participation and relying on mitigation. Bonneville’s previous comments also note that multiple other aspects of the DAME proposal result in mitigation that reduces market efficiency and is inconsistent with a fair and equitable market. 

Bonneville encourages CAISO to formalize a zonal procurement alternative as quickly as possible for stakeholder review. Bonneville leans toward supporting CAISO’s potential zonal alternative, but cannot do so without reviewing a formal proposal that directly compares aspects of both alternatives. Given the current status of the proposal, an adequate review of the zonal framework cannot be made, due to insufficient information. Bonneville would particularly like to see what a zonal construct would look like for all market participants, not just those in the CAISO footprint. It is critical that the CAISO spend sufficient time and resources to create a comprehensive zonal design, rather than rush this process to meet the schedule of May Board of Governors and Governing Body meetings. Bonneville is significantly concerned that the focus on sticking with this particular timeline will come at the expense of thorough consideration for a critical aspect of the market design. Doing so would be a disservice to stakeholders and potentially lead to significant issues needing to be resolved through tariff changes.

Bonneville also wants to highlight the concerns we have regarding the SCE proposal to move the Imbalance Reserve (IR) calculation from the Integrated-Forward Market (IFM) and into the Residual Unit Commitment (RUC) process. This would be a significant change from how the RUC optimization is currently done and we would have concerns about unanticipated market impacts. Bonneville would therefore encourage the CAISO keep the IR calculations in the IFM and separate from the RUC process.

In previous DAME comments, Bonneville, along with other non-California entities, have shared concerns that the current proposal will potentially lead to excessive market power mitigation. Bonneville requests that the CAISO consider the aspects of their design that lead to systemic over-mitigation, which suppress market clearing prices in the short-term and weaken participation incentives. In the long-term, inadvertently discouraging participation by over mitigating will distort price signals and deter long-term development. Therefore, Bonneville encourages the CAISO to carefully consider the current and future impacts of market design on prices.  

[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 03/30/2023, 12:22 pm


Shawn-Dai Linderman (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The California Community Choice Association (CalCCA) recommends the California Independent System Operator (CAISO) modify the final proposal to include a settlement mechanism to allow load-serving entities (LSEs) and generators to make transfers of capacity revenues consistent with the terms of their Resource Adequacy (RA) contracts. A settlement mechanism is necessary and compatible with the nodal, zonal, or Southern California Edison Company (SCE) approaches, since all three options could change RA bidding rules by allowing RA resources to bid in at a non-zero price and to receive a capacity payment if the market awards them Imbalance Reserves or Reliability Capacity.

With this change, many RA contracts would require RA resources to transfer revenues from capacity payments from the CAISO market to LSE counterparties given the LSE counterparty already paid for the capacity through the RA contract. Because RA resources currently receive capacity payments through RA contracts and not through the CAISO market, many RA counterparties do not have the systems and processes in place to facilitate the transfer of such payments. However, the final proposal does not include any way to facilitate the transfer of those revenues from generators to LSEs, which could result in LSEs paying generators twice for the same capacity: once through the RA contract and again through the Imbalance Reserve or Reliability Capacity payment.  In order to avoid this result, LSEs and generators would need to perform their own individual settlements to transfer the capacity revenues from the CAISO to the LSE. Such a process would be onerous given the large number of entities and volume of transactions. 

To avoid duplicative capacity payments and reduce the burden on market participants, the CAISO must modify the final proposal to allow inter-scheduling coordinator (SC) trades for both Imbalance Reserve and Reliability Capacity payments to allow RA counterparties to transfer revenues consistent with their RA contracts. Allowing inter-SC trades for Imbalance Reserves and Reliability Capacity would facilitate the transfer of revenues from Imbalance Reserve and Reliability Capacity payments while also not dictating how capacity payments would be allocated between counterparties, as inter-SC trades are an optional service both counterparties must agree to. CalCCA’s comments on the draft final proposal provide additional detail regarding how the CAISO could simplify the implementation of an inter-SC trade.[1]

In the Revised Final Proposal, the CAISO should include the inter-SC trade functionality for Imbalance Reserves and Reliability Capacity to allow LSEs and generators to make transfers of capacity revenues consistent with the terms of their RA contracts.


[1]             CalCCA Comments to the Draft Final Proposal:

California Department of Water Resources
Submitted 03/24/2023, 05:03 pm


Rodrigo (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The California Department of Water Resources (CDWR) appreciates the opportunity to comment on the DAME final proposal and continues to support the development of the Imbalance Reserve (IR) and Reliability Capacity (RC) products in the Day-Ahead Market. These new products are essential in the new day-ahead market design and will improve market efficiency and effectiveness.


The Nodal Approach versus the Zonal Approach


CDWR supports the CAISO’s nodal approach to IR/RC procurement for the following reasons:

  • The nodal approach results in more accurate prices because they represent a locational value of flexible reserves, similar to energy.
  • The nodal approach would not award and pay for reserves on resources behind constraints and undeliverable in the day-ahead timeframe.
  • The nodal approach is consistent with the existing price formation and Flexible Ramping Product (FRP) modeling.  CDWR also notes that the CAISO anticipates starting the Ancillary Services Deliverability and Real-Time Re-optimization initiative in 2023 to look at changing the procurement of Ancillary Services from a zonal approach to a nodal approach.


CDWR also believes the nodal approach will result in more accurate IR quantity procurement.  Procuring excess or insufficient IR will only exacerbate the net load variability and uncertainty problem between the day-ahead and real-time markets.


Imbalance Reserves Offer Requirements


CDWR continues to:

  • Support no IR must-offer requirements for Resource Adequacy (RA) resource capacity with self-scheduled energy bids.
  • Support voluntary RCD requirements from any RA resources, but prefer voluntary RCU/RCD requirements from use-limited resources in general.  Use-limited resources are associated with uncertainty (for example hydrology-based hydro resources) in their operation and relying on RC from use-limited RA resources would not address the uncertainty that the RC products would be expected to accomplish. CDWR believes a voluntary approach for providing RC from use-limited resources would be desirable.
  • Seek confirmation that a Participating Load (PL) that is a pumping load is not required to offer IR and RC products. Currently, in the Final Proposal (page 57), Participating Load is deemed eligible to provide RC and/or IR (dependent on its dispatch capability).  Under current CAISO Tariff section (Ancillary Services Bids from Participating Load that is Pumping Load), a resource adequacy PL that is a pumping load, using the extended non-participating load model, is only allowed to offer non-spin (with an option for contingency only) in the DAM and offer energy bid in RTM for the DAM AS non-spin award to meet RA obligation. This specific model will not allow offering IR or RC products.
  • Reiterate prior comment that current BPM of Reliability Requirements (Section 7.1.1) adds confusion as to which RA resources are required to submit RUC availability bid.  Pumping Loads and Hydro Units without qualifying use limits are not required to submit RUC availability bids. Qualified Use-Limited Resources, such as Hydro Units and Participating Loads, would be required to submit RUC availability bids. CDWR believes that the BPM description contradicts Tariff Section, that Hydro Units and Pumping Loads are not required to submit RUC availability bids for providing RA capacity. CDWR requests that the CAISO aligns the BPM with its Tariff section to clarify that the Pumping Loads irrespective of Use-Limited Resource status are not required to submit the RC availability bids under DAME.


Congestion Revenue Right Issues


As mentioned in the CRR comments previously submitted to the DAME proposal, CDWR is concerned about the implementation of the DAME CRR design because the CAISO proposes a DAME CRR design similar to the Day-Ahead (DA) CRR design in which the allocated and auctioned CRR are paid from the same CRR Balancing Account.


Since the current implementation on April 1st 2009, the DA CRR design has consistently resulted in higher shortages in the CRR Auction Efficiency, meaning that the auction participants’ benefits are paid by the Load Demand.  The shortages in the DA CRR Auction Efficiency amounted to over $1 billion for the 2009-2018 period, with an average of $100 million per year and the highest yearly value of $140 million for 2018.


In 2018, to reduce the shortages in the CRR Auction Efficiency described above, the CAISO initiated a stakeholder process, and as a result, implemented Track 0, Track 1A, and Track 1B DA features intended to provide the following improvements to the DA CRR design:


  1. Track 0 implemented better reporting of scheduled outages and reduced the Available Transmission Capacity for the annual CRR allocation and auction processes from 75% to 65% of the Total Transmission Capacity (TTC).
  2. Track 1A eliminated the possibility of nominating CRR from source-to-source locations since CAISO studies presented at the above-mentioned stakeholder process showed that 85% of the Auctioned CRR were source-to-source nominated.
  3. Track 1B ensured that Allocated and Auctioned CRR on each path do not get paid more than the congestion rents collected in that path, by introducing derates of the CRR payments based on the transmission constraints on each path. In theory, Track 1B should have eliminated the shortages in the CRR Auction Efficiency.


After their implementation, the Track 0, Track 1A, and Track 1B DA CRR design features provided relatively good protection to the CRR Auction Efficiency for Q1 – Q3 of 2019. However, starting with the 2019 Q4, the shortages in the CRR Auction Efficiency have increased steadily. The CRR Quarterly Market Performance Report shows that for Q1-Q4 2022, the shortage in the CRR Auction Efficiency reached the highest levels seen prior to the implementation of the above-mentioned CRR design features.


Per CAISO, similar to the DA CRR design, the DAME CRR design would achieve the CRR Auction Efficiency because the Track 1B design feature would ensure the DAME CRR would not be paid more than what is collected in the DAME congestion rents.


In the DAME Final Proposal the CAISO acknowledges that, for the DAME CRR design, in addition to the Track 1B transmission binding constraints, there would be new binding constraints to improve congestion revenue sufficiency resulting from the IR deployment scenarios. Moreover, the CAISO acknowledges these new IR binding constraints would create additional shortages in the DAME CRR congestion revenue sufficiency. The CAISO proposes to eliminate these shortages by collecting additional congestion rents through an uplift to IRU/IRD deployment. However, CDWR considers the CAISO’s proposal would do little to avoid the increase in the congestion revenue sufficiency resulting from the IR deployment for the following reasons:


  1. Even though the Track 1B binding constraints ensure that allocated and auctioned CRR would not be paid more than what was collected in the DA congestion rents, as acknowledged by the CAISO in the Quarterly Market Performance reports, the congestion revenue sufficiency is not achieved because the benefits of the auctioned CRR are paid from the joint allocated and auctioned CRR Balancing Account.
  2. Although not a direct payment to the benefits of the allocated CRR, the shortages in the congestion revenue sufficiency are paid by the Load Service Entities (LSEs) who receive less congestion revenues than the LSE’s congestion rents.
  3. The CAISO proposes that congestion revenue shortfall resulting from the IRU/IRD deployment is paid via the IRU/IRD uplift cost for allocation, however, that would provide little protection to the LSEs since most of the time, the LSEs are responsible for paying the IRU/IRD uplift costs.


For all the reasons described above CDWR does not support the implementation of a DAME CRR design that resembles the DA CRR design.


CDWR will support a DAME CRR design that separates the CRR Allocation processes from the CRR Auction processes.


California Energy Storage Alliance
Submitted 03/30/2023, 11:16 pm


Sergio Dueñas (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The California Energy Storage Alliance (CESA) appreciates the opportunity to provide feedback and recommendations on the materials and proposals presented during the DAME workshops hosted by the California Independent System Operator (CAISO or ISO) on February 27 and March 7-8, 2023. Importantly, CESA is grateful for the ISO staff’s responsiveness to and willingness to consider stakeholder feedback following the posting of the Final Proposal (FP) on January 11, 2023. We, like other stakeholders in this initiative, are convinced that having the detailed policy discussions that we’ve engaged in recently will materially improve the policy that the ISO ultimately pursues and its implementation.


The ISO should adopt a zonal-based approach for the procurement of Imbalance Reserves (IR)


During the aforementioned DAME Workshops Vistra and the Western Power Trading Forum (WPTF) presented on the benefits of a zonal-based approach for the procurement of IR. Both these parties argued that, in contrast to the ISO’s proposal to use a nodal approach for the design of the IR product, a zonal approach would be more aligned with the design of all other ancillary services (AS), the experience of market operators across the US, and the granularity in which load and variable energy resource (VER) uncertainty materializes. Crucially, WPTF also underscored that a zonal approach would represent significantly fewer implementation hurdles, less market design complexity, and shorter market runs.


CESA agrees with these arguments given the prevalence of zonal AS designs within and outside California. While we understand the CAISO’s intent to stay ahead of the curve by potentially leapfrogging a zonal design to move to a nodal one, market participants make adequate arguments in favor of simplified implementation to allow for lessons learned and improvements. Moreover, despite how the ISO staff characterized these alternatives within the Comparison Matrix shared March 20, 2023, CESA does believe that zonal-based alternatives offer relatively fewer and lesser implementation and market design risks given the existing familiarity with this framework for other AS.


As such, CESA encourages the ISO to consider a zonal approach for the procurement of IR. Specifically, CESA supports the approach that would allow for balancing authority areas (BAAs) to

define sub-BAAs zones. This ability will be crucial for BAAs participating in the Extended Day-Ahead Market (EDAM) which may desire to better represent their zonal variances.


Southern California Edison’s (SCE) approach for IR procurement is not a preferred outcome given the inefficiencies it would entail


?During the aforementioned DAME Workshops SCE presented on an alternative solution for the debate regarding whether a zonal or nodal approach should be pursued for the procurement of IR. SCE’s proposal basically moves the procurement of IR from the Integrated Forward Market (IFM) to the Residual Unit Commitment (RUC) process. Doing this has several effects that go well beyond eliminating competition between IR and energy for transfer capacity that the zonal proposal would also eliminate. SCE proposal would also eliminate all co-optimization benefits related to the procurement of IR and eliminate the ability to value, reserve, and compensate fifteen-minute ramp capability attributes, significant deficiencies relative to both nodal and zonal proposals.


CESA considers that the co-optimization and efficiency benefits allowing CAISO to value and compensate for fifteen-minute ramp capability associated with the creation of IR should be preserved and recognized as a key feature and an important part of the raison d’être of the IR product. As such, we do not consider SCE’s alternative for IR procurement to lead to the outcomes the ISO and the stakeholder community should deem desirable. Thus, we urge the ISO to refrain from considering SCE’s alternative for IR procurement. ?


The ISO should consider eliminating downward products from the DAME proposal


During the Workshop held February 27, Vistra presented on the potential for removing downward products (both IR and Reliability Capacity [RC]) from the DAME proposal. Vistra’s argument underscores that the Western Energy Imbalance Market (WEIM) currently has more than enough downward capability. In this context, development of new downward products is likely to regularly price these products at $0 or even at negative values given the surplus. Given this minimal benefit, Vistra notes that it is possible that the added complexity of developing downward products is actually unwarranted and could be avoided by their elimination.


CESA appreciates Vistra’s detailed consideration of this question, as well as the evidence they gathered and presented to stakeholders. From an energy storage perspective, the development of downward products that would routinely clear at close to $0 prices poses significant risks. This is particularly true given the fact that battery energy storage systems (BESS) will be uniquely well positioned to provide IR. In this context, development of a product that would not compensate these resources while making them incur additional milage is definitely concerning. As such, in light of the data presented by Vistra, CESA urges the ISO to consider simplifying the DAME proposal by eliminating consideration of downward products (IR and RC). CESA believes that this outcome will be beneficial for the overall policy development of DAME as it may allow staff to dedicate additional time to refining other aspects of the policy discussed therein. ?


The ISO should include modifications to the formula that governs state-of-charge (SOC) calculations in the Day-Ahead (DA) market


Since late February, CESA and a subset of our membership has engaged with ISO staff to brainstorm around ways in which the impacts of IR could be represented in the day-ahead market in order to mitigate the potential for unfeasible awards, an issue that was recognized by the ISO in the FP posted January 2023. In our conversations with ISO staff, CESA and our members expressed that the ISO should seek to incorporate the effects of IR in two formulae: the SOC calculation and the AS SOC constraint. These formulae for the DA market, described in the Market Operations Business Practice Manual (BPM) version 78, Section, are as follows:

  • DA SOC Calculation:[1] SOCi,tSOCi,t-1-(Pi,t++ηiPi,t-image-20230330231525-1.png)   
  • DA AS SOC Constraint: SOCi,tSRi,t+RUi,t+NRi,tSOCi,tSOCi,t-ηiRDi,timage-20230330231525-2.png


CESA proposes to modify the formulae described above as follows:

  • Proposal for DA SOC Calculation:[2] 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-20230330231525-3.png)   
  • Proposal for DA AS SOC Constraint: SOCi,tSRi,t+NRi,t+μi,t+,RURUi,t+μi,t+,IRUIRUi,tSOCi,tSOCi,t-μi,t-,RDηiRDi,t-μi,t-,IRDηiIRDi,timage-20230330231525-4.png


As it can be seen from the formulae above, CESA proposes three key modifications:

  1. Inclusion of the impacts of IR Up and IR Down, with their own multipliers, in both the DA SOC Calculation and the DA AS SOC Constraint.
  2. Inclusion of multipliers for Regulation Up and Regulation Down within the DA AS SOC Constraint.
  3. That all aforementioned multipliers are resource specific.


CESA understands that incorporating these recommendations is challenging given the timeline of this initiative. These challenges are further impacted by the fact that we do not have conclusive data that would allow us to understand the feasibility of IR needs materializing by hour. In addition, we understand that the CAISO will take a more comprehensive look at the AS SOC Constraint in a separate initiative later this year. 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-20230330231525-5.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
    • Commit to consider more significant modifications in the AS SOC Constraint initiative, like the ones include in CESA’s proposal above
    • Commit to testing prior to implementation scenarios that would identify whether any inefficient or infeasible awards result from different multipliers in the SOC calculation than in the AS SOC constraint.


[1] Note this formula does not include the improvements approved as part of the Energy Storage Enhancements (ESE) Initiative.

[2] Note this formula includes the improvements approves as part of ESE, as well as CESA’s proposed enhancements.

California ISO - Department of Market Monitoring
Submitted 03/31/2023, 03:51 pm


Ryan Kurlinski (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

For a fully formatted version of DMM's comments, please see the attached pdf.  The text in the comments pasted in this box should be identical to the text in the pdf, but there may be some formatting differences.

Comments on Day-Ahead Market Enhancements March 2023 Workshops

Department of Market Monitoring

March 31, 2023


The Department of Market Monitoring (DMM) appreciates the opportunity to comment on the Day-ahead market enhancements – March 2023 workshops.[1]

The ISO’s initial DAME design proposed utilizing a penalty price greater than the IFM offer cap (i.e. > $1,000/MWh) to procure upward imbalance reserves sufficient to cover 97.5% of net load uncertainty between the day-ahead and 15-minute markets.  This valued each MWh of the product, up to that 97.5% uncertainty level, as a requirement that had to be met, without considering the actual economic value of buying imbalance reserves in the IFM.  The main justification for placing such a high value on imbalance reserves appears to be that a high level of imbalance reserves may be necessary in the IFM for balancing areas to have confidence in the deliverability of EDAM transfers – and that the additional costs from using an uneconomic penalty price to procure a pre-determined “requirement”, or from inflating the demand curve above an accurate valuation, may be justified by the added assurance that sufficient capacity will be available in real-time to support EDAM transfers.

However, DMM believes that procuring a high level of imbalance reserves in the IFM, such as the previously proposed 97.5% requirement, would be inadequate for achieving this goal of ensuring confidence in EDAM transfers, while adding unnecessary costs to the day-ahead market.  This inadequacy of the imbalance reserve product should not adversely impact the successful implementation of EDAM because having this product in the IFM is not necessary for EDAM.  With or without the imbalance reserve product in the IFM, balancing areas will need to utilize the EDAM net export constraint in order to ensure confidence in EDAM transfers.  And use of the constraint will ensure deliverability of EDAM transfers in the absence of any imbalance reserve product in the IFM.  If participating balancing areas feel EDAM should determine a real-time must offer obligation in excess of load forecast, it would be more appropriate to incorporate the uncertainty adder into RUC and use RUC to determine this must offer obligation.

DMM appreciates that the ISO has now proposed a downward sloping demand curve for imbalance reserve procurement.  However, as the Market Surveillance Committee (MSC) explained at its March 10, 2023 meeting, the proposed demand curve still drastically overstates the actual value of procuring each MWh of imbalance reserve capacity in the IFM.  Any overvaluing of the demand curve will add unnecessary costs to the day-ahead market while still falling significantly short of a capacity level that could create confidence in the reliability of EDAM transfers or the resulting real-time must offer obligation.  Therefore, if the ISO proposes to include an imbalance reserve product in the IFM, DMM recommends that the ISO focus its efforts on determining the actual value of this capacity.  The value of day-ahead imbalance reserves, as represented by demand curve prices, would be significantly less than  the value of the real-time flexible ramping product.  DMM also continues to recommend that the ISO expand the supply counted towards meeting imbalance reserve product demand to capacity that resources can ramp to over several hours, rather than limiting supply to 15-minute capacity.


The demand curve for an imbalance reserve product in the IFM should be significantly lower than the ISO has proposed

The ISO’s initial DAME design proposed procuring imbalance reserve up (IRU) sufficient to cover 97.5% of net load uncertainty between the day-ahead and real-time, with a penalty price greater than the IFM offer cap (i.e. > $1,000/MW).  In response to concerns this could overvalue IRU, the ISO is now proposing to procure IRU using a demand curve. However, as noted at the most recent Market Surveillance Committee (MSC) meeting, the ISO’s proposed demand curves have had prices far higher than the value of procuring imbalance reserves in the day-ahead market.[2]

The IRU demand curve should represent the value of procuring additional reserves in the IFM relative to not procuring the IRU reserves.  To illustrate, consider the flexible ramping product (FRP) demand curve. The FRP demand curve is the marginal value of reduced expected power balance violation costs from procuring additional flexible reserves—assuming no other options exist to respond to net load uncertainty from one market interval to the next.[3] If there were other non-FRP capacity available to respond to net load errors, than the value of FRP would be less. The FRP value would be lower because this other capacity could respond to net load outcomes and avoid the potential power balance violation costs even if no FRP were procured. The value of buying an option to respond to uncertainty through an explicit market product decreases as the number of resource options available even without the explicit market product increases.

There are many options, other than IRU procurement, to respond to net load uncertainty in the hours between the day-ahead and real-time markets. Many of these options will be from capacity without IFM awards that are bid into the real-time markets. Significant portions of capacity receiving IRU awards are also likely to bid into the real-time markets without an IRU award. The main mechanism for resolving uncertainty between day-ahead and real-time is the real-time market and prices.  The potential to profit from real-time market sales gives entities reason to participate in the real-time market even if they do not have a real-time must offer obligation. The residual unit commitment, real-time FRP, and other potential products or actions can provide additional options or better manage existing options. Given the available options, the value of procuring IRU relative to not procuring IRU is likely to be relatively low.

If the ISO proposes a demand curve with prices significantly more than a few dollars per MWh, staff should demonstrate how they calculated the value of the capacity to determine these prices.  Setting IRU demand curve prices above the marginal value of the capacity would reduce day-ahead market efficiency because it would result in IRU procurement costs exceeding the actual value of the procured capacity.  In addition, as described in following sections of these comments, procuring IRU in the IFM may provide very limited – if any – reliability benefits.

Procuring IRU in the IFM may decrease physical supply and demand clearing IFM and increase reliance on RUC for scheduling physical supply

As also discussed at the March 10 MSC meeting, procuring IRU in IFM based on demand curves that overvalue IRU may decrease physical supply and demand clearing IFM and increase reliance on RUC.  When IRU is procured in the IFM along the demand curve, this will drive day-ahead energy prices up relative to real-time prices.  This energy price increase would tend to increase virtual supply and decrease physical demand clearing IFM.  This virtual supply and any physical load not clearing IFM would increase the amount of capacity scheduled in the RUC process to ensure reliability.   The potential for this market dynamic increases with the degree to which IRU is overvalued in the demand curve used in the IFM.

A demand curve that overvalues imbalance reserve product in the IFM would be insufficient for ensuring adequate capacity to support EDAM transfers

Even an extremely overvalued imbalance reserve demand curve in the IFM would not ensure adequately reliable EDAM transfers or real-time must offer obligations.  Even a somewhat less overvalued imbalance reserve demand curve would still create inefficient cost increases, as described above.  But it is unclear how any overvalued IRU demand curve would enhance EDAM. 

The ISO has previously proposed utilizing a penalty price greater than the IFM offer cap (i.e. > $1,000/MW) to procure upward imbalance reserves sufficient to cover 97.5% of net load realizations.  DMM has explained in prior comments that even this extreme overvaluation of imbalance reserves in the IFM would leave the real-time must offer obligation determined by the extended day-ahead market short of standard reliability criteria.[4]  If balancing area operators relied on even this extreme overvaluation of imbalance reserves, the EDAM footprint’s real-time must offer obligation would still be expected to be insufficient to meet net load in more than one day out of every 50.  This level of reliability is almost 2x orders of magnitude lower than standard reliability criteria such as no more than one day of load shed every 3,650 days.  As a result, it seems unlikely that procuring day-ahead imbalance reserves at this level would be sufficient to impact decisions operators must make to ensure grid reliability under stressed system conditions.

Moreover, if an EDAM area allows convergence bidding, virtual supply can cause the balancing area to assume responsibility for real-time load curtailment even if the area provided sufficient capacity to cover its obligations in EDAM.[5] This can occur even when uncertainty materializes at a much lower level than the 97.5% threshold if another EDAM balancing area has failed the EDAM resource sufficiency evaluation.

Therefore, as DMM explained in prior comments, EDAM’s net export constraint is a critical aspect of the EDAM design that will need to be utilized by EDAM balancing areas in tight system conditions regardless of how much the DAME market design ultimately overvalues an imbalance reserve up product in the IFM.[6]  In conditions when EDAM balancing area operators have concern that sufficient capacity may not bid into real-time markets to meet the footprint’s reliability needs, areas with sufficient capacity bidding into the EDAM will still need to determine how much excess capacity the areas can make available for EDAM transfers out.  These capacity sufficient balancing areas will need to set their net export constraints accordingly. 

As a result, overvaluing the imbalance reserve demand curve in the IFM would likely provide no appreciable reliability benefit, but, as explained above, it could result in significant EDAM cost increases. 

A real-time must offer obligation for EDAM balancing areas may have very limited impact on operator use of net export constraint

DMM understands that having a mechanism that sets a real-time must offer obligation in excess of each balancing area’s day-ahead load forecast could in theory add value to the overall EDAM design.  The EDAM resource sufficiency evaluations will incorporate capacity requirements in excess of load forecasts set at a level that EDAM balancing areas have mutually agreed is adequate for demonstrating that no area is trying to lean on EDAM to avoid forward capacity procurement.  Having a mechanism within EDAM that creates a total real-time must offer obligation for the footprint similar to the sum of the footprint’s EDAM RSE requirements may increase balancing area operators’ confidence in the amount of capacity across the footprint that will ultimately show up in real-time.

A real-time must offer obligation could increase EDAM efficiency if this increased operator confidence causes operators to increase their net export constraint limits, or even turn off the constraints, in some conditions.  Less use of the net export constraint could increase the quantity of mutually beneficial trade between EDAM areas.

However, it is not clear that a real-time must offer obligation set by EDAM would significantly change operators’ use of the net export constraint.  First, the current EDAM design seems to include no incentives, besides exposure to buying back day-ahead awards at real-time prices, for resources with real-time must offer obligations to participate in the real-time market.[7]  Therefore, resources assigned real-time must offer obligations by EDAM have the same incentives to participate in the real-time market as resources without real-time must offer obligations: i.e. exposure to real-time market product prices.  As a result, an EDAM balancing area is likely to decide when and how high to set the net export constraint limit based on its assessment of footprint-wide resource availability relative to demand, and the possibility that the footprint might be short.  The existence of a real-time must offer obligation determined by EDAM for each balancing area may have little practical impact on how the balancing area’s operators set the area’s net export constraint.

As described above, if another EDAM balancing area fails the EDAM RSE or if uncertainty materializing above a 97.5% threshold could result in an EDAM footprint capacity shortfall, meeting a balancing area’s standard reliability criteria (such as loss of load in less than one day in 10 years) would entail operators limiting net EDAM transfers out to capacity that is safely in excess of the balancing area’s needs.  So, in tight system conditions, a real-time must offer obligation in excess of load forecast would not be likely to impact a balancing area’s use of the net export constraint.

In situations where there is abundant capacity in the EDAM footprint to support the realization of high net loads, DMM questions whether the existence of the real-time must offer obligation assigned through EDAM would impact operators’ procedures for using the net export constraint.  It seems likely that operators would avoid the extra burden of determining when there is a non-negligible risk of a footprint capacity shortfall.  Operators may instead always use the same procedure to set the net export constraint equal to the extra capacity that they think their balancing area can sell.  Conversely, operators might not be inclined to use the net export constraint on days when high uncertainty materializing would not create concern for a footprint capacity shortfall.  Whether or not the EDAM creates a real-time must offer obligation that might ensure loss of load in less than one day out of every 50 is unlikely to play any role when a balancing area operator makes the determination to not use the net export constraint given that their objective is to manage the grid to reliability levels 2 orders of magnitude greater.

DMM understands that there may be other reasons EDAM balancing areas would want EDAM to select which resources bidding into the EDAM resource sufficiency evaluations have real-time must offer obligations.  The next section explains why it would be better to determine the must offer obligation in the physical-only RUC process than in the financial IFM.

If potential EDAM balancing areas think there is sufficient value in EDAM determining real-time must offer obligations, RUC could more effectively achieve this than the IFM

EDAM RSE is intended to represent a capacity requirement level that participating EDAM balancing areas have agreed is sufficient for each balancing area to feel the other balancing areas have brought sufficient capacity to the extended day-ahead market process.  DMM understands EDAM balancing areas could view there being significant value in ensuring that the EDAM footprint capacity that gets assigned a real-time must offer obligation meets the standards set by the EDAM RSE.  DMM agrees with views expressed by Southern California Edison at the workshops that RUC could accomplish this more effectively than the IFM.[8]

First, as explained above, the IFM is a financial market that allows virtual bids to converge IFM outcomes to expected real-time outcomes.  If an uncertainty product in the IFM, such as imbalance reserve, places value on capacity for meeting outcomes that are not expected to occur, virtual bids should profitably displace the physical resources that would be optimally procured in a physical only market.  Therefore, the RUC capacity market remains necessary for procuring the physical capacity that will be needed to meet net load in situations when the real-time net load realization differs from the expected outcome that the financial IFM market converged to.  By removing the demand for capacity to meet this uncertainty from the IFM and including it instead directly in RUC, the day-ahead market can avoid the inefficiency of paying virtual and other financial awards to displace physical capacity that RUC will ultimately still have to procure.

Next, as DMM explained in prior comments, the EDAM design currently allows load in a balancing area that failed the EDAM RSE to “cure” its capacity deficiency and still be included in the EDAM pool for WEIM RSE simply by economically bidding enough of its demand forecast into the IFM.  This aspect of the EDAM design creates the possibility that one EDAM balancing area’s capacity shortfall could cause the entire EDAM pool to fail the WEIM RSE. [9]  Adding uncertainty to RUC and using RUC to determine if EDAM can cure a balancing area’s EDAM RSE insufficiency would help to mitigate this concern.

An imbalance reserve product in the IFM is not needed to ensure confidence in EDAM transfers

DMM understands that the intent of procuring a large amount of imbalance reserves in the day-ahead market is to ensure that balancing areas have confidence in the deliverability of EDAM transfers.  From this perspective, the additional costs from procuring IRU may be justified by the added assurance that sufficient capacity will be available in real-time to support EDAM transfers.  DMM disagrees with this reasoning, and believes that imbalance reserves in the IFM are not needed for EDAM’s initial implementation to be successful. 

The ISO’s final EDAM proposal includes the net export constraint.  As explained in prior comments, the net export constraint is a critical element of the EDAM design, even if imbalance reserves were procured with the clearly excessive valuations for high levels of uncertainty proposed in earlier ISO papers.[10] The constraint allows each EDAM balancing area to limit its EDAM transfers out to only the capacity that its operators determine is in excess of its own balancing area’s reliability requirements.

Before the EDAM runs on any day in which there is uncertainty over there being sufficient real-time capacity to meet the EDAM footprint’s net load, each EDAM balancing area’s operators can determine how much capacity its area needs given load uncertainty and how much capacity the area will have available.  The net export constraint will allow the area’s operators to ensure that EDAM transfers do not cause the balancing area to assume responsibility for load curtailments caused by another balancing area with a capacity shortfall.  If neither the IFM nor RUC could be relied upon to assign sufficient real-time must offer obligations to generation in other balancing areas, the net export constraint allows an area with sufficient capacity to make its extra capacity available for mutually beneficial trade without jeopardizing its own reliability.  As a result, implementing the EDAM proposal without imbalance reserve in the IFM should still allow participating balancing areas with excess capacity to ensure reliability while realizing significant benefits from trade.

The ISO’s final EDAM proposal approved by the board in January did not include details of most of the significant elements of a potential imbalance reserve product in the IFM.  DMM supported the EDAM proposal despite the potential for the ISO to not complete a reasonable imbalance reserve product design before needing to file its EDAM proposal with FERC.  This is because DMM does not believe the imbalance reserve product is required for EDAM’s initial implementation phase.      

The supply that counts as meeting imbalance reserve demand should be significantly increased

The ISO proposes to require imbalance reserves to be deliverable over only fifteen minutes to meet the forecast errors between day-ahead and real-time.

DMM’s analysis in past comments demonstrated that the entire forecast error between the day-ahead and real-time market for a given hour or interval would not be realized over only fifteen minutes. Rather, some of the errors are realized thirty minutes, one hour, or longer before the real-time interval. DMM analysis looked at the correlation of hourly errors between cleared day-ahead market net load and fifteen-minute market net load. There was significant correlation between errors in the hours shown and at least the previous three hours. This suggests that portions of the errors for a given hour are realized in previous hours. DMM also analyzed an example day that demonstrated that net load errors are similar across multiple intervals. This analysis showed that restricting all imbalance reserves to being rampable within fifteen minutes is overly restrictive.[11] At its March 10 meeting, members of the Market Surveillance Committee also demonstrated that the entire net load uncertainty between day-ahead and real-time does not materialize over just 15 minutes.[12]

Restricting the supply to 15-minute capacity could significantly inflate the costs of imbalance reserve product procurement above what is necessary to meet the actual demand.  Therefore, the ISO should allow hourly block intertie bids, longer start resources, and capacity levels that can be reached over several hours to count as meeting the imbalance reserve demand.  It would only be appropriate to limit the imbalance reserve supply to 15-minute capacity if the ISO limits the IFM demand to only the uncertainty that materializes 15 minutes in advance of power flow.

Locational versus zonal procurement

DMM’s understanding of the ISO’s locational procurement proposal is that it would be flexible in the constraints and contingencies that it modeled in the deployment scenarios in order to prevent its implementation from adversely impacting day-ahead market run performance.  This locational design with the enforced constraints limited to only the most important constraints does not seem meaningfully different from what proponents of zonal procurement were envisioning. 

DMM agrees with arguments made by members of ISO staff and the market surveillance committee at the workshops that local market power could be exercised even in a design that limited constraints to only those between EDAM balancing areas.  Therefore, with an imbalance reserve demand curve on the order of magnitude previously proposed by the ISO, a zonal approach would not avoid the complication of designing and implementing an appropriate mechanism for mitigating the potential exercise of market power.  However, with a demand curve that placed an appropriately low value on imbalance reserve procured in the IFM, such as the $5/MWh discussed in the workshops, there may not be a practical need for binding deployment scenario constraints to trigger energy and imbalance reserve bid mitigation. 

Therefore, DMM supports proceeding with a locational imbalance reserve procurement design, and encourages the ISO and stakeholders to focus efforts on the more significant issues discussed above:

  • the possible overvaluation of any potential demand curve greater than a few dollars per MWh in the IFM;
  • limiting supply to less capacity from each resource than can ramp over several hours to meet the uncertainty between day-ahead and real-time, which would be known several hours before power flow; and
  • potentially using uncertainty in RUC to determine a real-time must offer obligation that meets the excess capacity standards mutually agreed upon by participating EDAM balancing areas. 



[1] See presentations from meetings on 2-27, 3-7, 3-8, and 3-10-2023 on the ISO’s day-ahead market enhancements initiative website at:   

[2] Calibrating the Demand Curve for Imbalance Reserves, MSC presentation, Jim Bushnell, March 10, 2023:

[3] The FRP demand curve calculates the marginal option value of procuring additional flexible reserves. Because the calculation ignores the costs of exercising these options, i.e. ignores the energy dispatch costs, the FRP demand curve itself over estimates this value.

[4] For example, see Comments on extended day-ahead market straw proposal, Department of Market Monitoring, June 17, 2022, pp. 4-6:   

[5] Comments on extended day-ahead market draft final proposal, Department of Market Monitoring, November 22, 2022, pp. 5-7:

[6] Department of Market Monitoring report to ISO Board of Governors and WEIM Governing Body, January 25, 2023, pp. 2-4:

[7] The one potential exception DMM is aware of is for non-source specific imports—the EDAM policy is to exclude the balancing area from the EDAM pool for WEIM RSE if an import with an EDAM schedule does not participate in real-time.  However, this penalty is only for the balancing area.  The EDAM design does not actually create any incentives for the importer to participate in the real-time market.

[8] DAME Design Issues: Imbalance Reserve, Southern California Edison, March 7, 2023, pp. 6-7: 

[9] Comments on extended day-ahead market draft final proposal, Department of Market Monitoring, November 22, 2022, p. 8:

[10] Department of Market Monitoring report to ISO Board of Governors and WEIM Governing Body, January 25, 2023, pp. 2-4:

[11] Comments on Day-Market Enhancements Second Revised Straw Proposal, Department of Market Monitoring, August 18, 2021: 

[12] Normalized net load errors, MSC Presentation, Ben Hobbs, March 10, 2023:

Los Angeles Department of Water and Power
Submitted 03/30/2023, 09:54 pm


Stuart Kelly (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

See attachment


Middle River Power, LLC
Submitted 03/30/2023, 01:31 pm


Brian Theaker (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

Middle River Power LLC (“MRP”) appreciates the CAISO providing additional stakeholder process to consider issues with, and alternative designs for, the DAME capacity products. 

MRP continues to support the premise/problem statement underlying this initiative, namely, that implementing market capacity products that (1) provide CAISO operators with an “envelope” of deliverable operating capability to address uncertainty and (2) are procured in the Day-Ahead Market time frame would be preferable to CAISO operators securing the operational capacity they believe is needed through biasing the Residual Unit Commitment (“RUC”) demand forecast. 

While MRP shares some of the Western Power Trading Forum’s concerns about allocating thousands of MW of uncertainty on a nodal basis and how that allocation will affect other Day-Ahead market products and prices, MRP nevertheless believes that using a nodal design for these capacity products is likely the best, if not the only, way to ensure, to the maximum extent possible, that energy from these products can be delivered in real time.  MRP understands that differences in the network models arise between the Day-Ahead Market and the Real-Time Market, and that projecting deliverability in the Day-Ahead Market is no guarantee of real-time deliverability.

The conundrum, as MRP sees it, is that the CAISO understandably wants to (1) procure an amount of imbalance reserves that covers a very high level of historically observed uncertainty and (2) to ensure that such reserves are deliverable.    MRP also understands that the low likelihood of the entire amount of uncertainty materializing in real-time means that the CAISO will be “holding” a significant amount of network capacity to be able to deploy the full amount of imbalance reserves procured as needed.  Procuring imbalance reserves to cover a lower level of uncertainty requires holding less network capacity but may not fully ensure the energy from the reserves can be fully deployed if the amount of uncertainty that materializes is higher than the amount of uncertainty that was used in procuring imbalance reserves.  MRP believes it is prudent to procure imbalance reserves sufficient to cover a large amount of potential uncertainty but acknowledges there are tradeoffs with that approach.  

A second tradeoff that factors prominently in the DAME design discussion is whether to procure IR in a non-co-optimized way outside of the Integrated Forward Market (“IFM”) (e.g., SCE’s proposal to procure imbalance reserves in RUC) or whether to procure imbalance reserves co-optimized with the procurement of other products the IFM.  SCE offers that there is a strong argument for procuring the imbalance reserve capacity product outside of the IFM rather than “pretending” that these capacity products are IFM energy products.[1]   MRP believes this characterization of capacity products “pretending” to be energy products is too harsh.   By their very nature, capacity products are not energy products until the situation arises in which the energy from these products must be deployed.  In such situations, not being able to reasonably ensure the delivery of energy from these products puts reliability at risk.  Consequently, MRP offers that the IFM should procure, in a co-optimized way, all the products, both capacity and energy, that the CAISO requires to reliably operate the system, and it is reasonable to take steps to best ensure that energy from those products can be delivered in real-time as may be needed.  MRP therefore does not support SCE’s proposal for procuring imbalance reserves in RUC and not in the IFM. 

Some parties have raised the issue of nodal imbalance reserves affecting or crowding out the procurement of imbalance reserves.  MRP offers that if the CAISO believes that the nodal procurement of imbalance reserves and reliability capacity is required to ensure the deliverability of energy from those capacity products, the CAISO may wish, for the same reason, to consider whether nodal procurement of ancillary service products is also warranted.   The parallels seem clear: the CAISO may only need to deploy energy from contingency reserve under certain infrequent circumstances, but that energy must be deliverable if those circumstances arise.

In conclusion, MRP reiterates its appreciation for the CAISO stepping back to hold workshops to consider the complex issues implicated in the development and deployment of imbalance reserves and reliability capacity.  That pause created a more robust discussion around these products, which MRP hopes the CAISO can continue and not unduly truncate.  MRP supports the CAISO’s current direction of the DAME design, with some caveats, but would support further discussion on the issues raised in the workshops. 


[1] SCE March 7, 2023 presentation DAME Design Issues: Imbalance Reserves at page 6.

NV Energy
Submitted 03/30/2023, 06:57 pm


Lindsey Schlekeway (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

NV Energy supports the CAISO’s efforts to take a step back and conduct stakeholder workshops, allowing stakeholders to voice alternate proposals and discuss concerns with the current proposed design of the DAME. The workshops and the Market Surveillance Committee (“MSC”) meeting were very informative and helpful to gain a clearer understanding of the CAISO’s proposal for the DAME initiative. While NV Energy was hopeful that the discussions would ease some of NV Energy’s reservations regarding the proposed Imbalance Reserve Product (“IRP”) and the Reliability Unit Commitment (“RUC”) process, the concerns stated during the workshops caused NV Energy to have deeper reservations and hesitation regarding the IRP. Issues were raised during these meetings regarding: (1) the quantity of IRP, the quality of the product, and the price impact to customers. NV Energy is still concerned that the proposed IRP will procure too much 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”).


Additionally, NV Energy reiterates its previous concerns -- that neither blanket statements of potential benefits nor a high-level study with unexplained and unsupported assumptions provide enough support regarding the need for the Imbalance Reserve 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 proposes that CAISO remove the IRP from the DAME initiative 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, CAISO should consider other 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:


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. NV Energy agrees with this assessment and is also concerned that the currently designed product may artificially increase prices in the Day Ahead Market. This is an unacceptable outcome considering the uncertainty may never materialize. NV Energy would be more supportive of a product that procured for a longer ramp like the MSC proposed or a significant reduction in the uncertainty that is procured when implementing the product. However, NV Energy believes the best course of action would be to remove this product from scope of this initiative to allow time for market pricing analysis to occur.


The MSC members also mentioned concerns regarding whether it would be appropriate for storage resources to receive IRP awards and that the product may commit additional thermal resources than needed on lower load days.  NV Energy is also concerned about these market inefficiencies which could significantly reduce the benefits that the IRP is intended to create for the market. Additionally, CAISO should really consider how this product may impact the dispatch to different resource types.


An idea was presented by stakeholders to procure the capacity zonally rather than nodal procurement to simplify the design.  NV Energy cannot provide an opinion about if procurement zonally or nodally would be more appropriate but does believe that both options should be considered side by side to allow stakeholders to see the comparison of these two options.  CAISO published this matrix on March 20, 2023, but NV Energy needs more time to consider the advantages and disadvantages of each product within its Balancing Authority Area before providing its opinion. Other ideas that were proposed included a proposal to remove the downward product. NV Energy supports the removal of the downward product especially since other markets only procure uncertainty in the upward direction and CAISO has not provided any data supporting the inclusion 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 be an issue for gas resources depending on the timeframe of the posted results. Therefore, NV Energy would like the CAISO to consider alternate proposals that would simplify the design or at least inform stakeholders whether the processing time is not an issue with the current design. Regardless, CAISO should communicate with stakeholders about the time Day Ahead results will be posted well in advance of implementation of all Day Ahead Market Enhancements.


Finally, CAISO proposed a revision to its final IRP design to collect congestion revenue through IR uplift. While NV Energy understands CAISO’s proposed addition to the final design, it does not support the proposed addition.  CAISO should really consider if it would be appropriate for load to pay for congestion of an uncertainty product, especially when that uncertainty is not likely to materialize. If CAISO continues to move forward with this new proposed design, then NV Energy proposes that CAISO only procure the amount of IRP that is expected to occur during greater than 50 percent of the intervals.


Demand Curve:


During the MSC meeting, the MSC members discussed the maximum price that was proposed to be used for the IRP demand curve.  NV Energy supports the comments made by the MSC members that the IRP should never have a higher priority than energy, especially since the uncertainty may not materialize and the market should never pay a scarcity price for uncertainty that may not materialize. Additionally, the members questioned whether $500/MWh was an appropriate price to pay for IRP or if that price would be too high to set the IRP demand curve. NV Energy believes that the demand curve should be set at $247/MWh as the highest price 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 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 will 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.  Additionally, this additional concern is yet another reason NV Energy does not support the current proposed RUC run to use all capacity within the EDAM footprint. 


Decisional Authority:

NV Energy strongly supports the joint authority designation for this initiative. As noted during the workshops and the MSC meeting the required imbalance reserve procurement would not only effect potential EDAM Entities but also would have a direct effect on EIM participants.

Pacific Gas & Electric
Submitted 03/30/2023, 11:45 am


JK Wang (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

See the attachment. 

Submitted 03/30/2023, 03:21 pm


Vijay Singh (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:


Creating novel market products that have minimal impacts to other market functionalities is a monumental task often requiring consideration of tradeoffs, at times with imperfect information. PacifiCorp appreciates the CAISO being willing to delay the Day-Ahead Market Enhancements (DAME) initiative to further debate the merits of the nodal and zonal designs for the imbalance reserve product as well as to allow stakeholders to better understand the CAISO’s initial proposal. The delay also gave PacifiCorp more time to better understand the implications the products will have on our operations. PacifiCorp retains its position that an uncertainty product is needed as the industry moves towards incorporating more variable energy resources (VERs) on the grid. The CAISO identified an inefficiency in the day-ahead market where operators utilize load biasing in the residual unit commitment (RUC) process for the purpose of having more physical capacity at the CAISO’s disposal if operators feel more resources are needed to be readily online. During this initiative, the CAISO outlined the major drivers of uncertainty as wind, solar, and load variance. As an entity committed to the Extended Day-Ahead Market (EDAM), PacifiCorp is vested in exploring practical options that will create an EDAM that market participants can have confidence in. After attending the recent workshops and working with internal subject matter experts (SME’s), PacifiCorp supports a nodal design with enhancements from the original CAISO proposal.

To summarize, PacifiCorp prefers a nodal design due to:

  • The uses of deployment scenarios to mitigate intra-Balancing Authority Area (BAA) transmission constraint concerns.
  • The increased diversity benefits for EDAM BAAs over other design options.
  • The implementation risks being at least equal, but most likely lower, than other design options.

PacifiCorp would also like the following considerations to be further discussed:

  • Ways to ensure the day-ahead market will be able to clear by 1pm.
  • Ways to improve the deployment scenarios to minimize the potential and risk of incorrect market signals.
  • Whether capping awards at a resource’s 15-minute ramping capability is too limiting.
  • How the imbalance reserve demand curves should be structured.
  • The use of tunable parameters for the constraints enforced by the deployment scenarios and the percentage of uncertainty requirement that is enforced in the deployment scenarios.


Use of Deployment Scenarios

During the stakeholder workshops, the discussion on what it means to be deliverable in the day-ahead market versus deliverable in the real-time market was important when considering how the imbalance reserve product should be designed to fit with the current transmission system. PacifiCorp believes a nodal market design will more effectively manage concerns with intra-BAA transmission constraints in the day-ahead market optimization through the proposed deployment scenarios. Whether the imbalance reserve design is nodal or zonal, PacifiCorp strongly advocates for the use of deployment scenarios to help ensure some portion of the imbalance reserve capacity is not trapped behind transmission constraints in the Integrated Forward Market (IFM). While PacifiCorp acknowledges that deliverability of imbalance reserves in the day-ahead timeframe does not necessarily equate to deliverability in real-time, PacifiCorp believes the CAISO’s day-ahead optimization processes can appropriately predict real-time system conditions. Therefore, some level of imbalance reserve ‘flow’ should be considered by the day-ahead market optimization. However, PacifiCorp does have concerns with the deployment scenarios, which will be discussed in more detail below. Once PacifiCorp is in EDAM, it will be prudent for the market to optimize in a way that manages the transmission risks before heading into real-time operations, giving EDAM BAA operators a good starting point to manage any real-time difficulties. PacifiCorp acknowledges that operators will likely always need to make adjustments for real-time due to variances between day-ahead and real-time conditions, but those adjustments will be less consequential if there is a high probability that resources awarded imbalance reserves are not behind constrained transmission pathways.


Increased Diversity Benefits

The diversity benefits from increased cooperation and market optimization in the day-ahead timeframe is key, and it is important that the diversity benefits of the imbalance reserve product are maximized. It is PacifiCorp’s opinion that one of the greatest benefits of the imbalance reserve product is being able to share imbalance reserve capacity among EDAM BAAs. The March 16th, 2023, Market Performance and Planning Forum Presentation given by CAISO staff highlighted how the nodal Flexible Ramping Product (FRP) requirement is being spread across the WEIM footprint.[1] While there is not yet a substantial amount of data on the FRP since it started being procured nodally, the CAISO data shows only a few resources from a subset of WEIM BAAs have been needed to cover the FRP requirement. While the EDAM footprint, at least at the start, will be smaller than the current Western Energy Imbalance Market (WEIM) footprint, the nodal FRP shows the diversity benefit of being able to pool flexible reserves among multiple entities across a wide geographic region. PacifiCorp acknowledges that imbalance reserve capacity could be shared among BAA zones in a zonal design, but it is PacifiCorp’s opinion that deployment scenarios would still be needed to give confidence to market participants that transfers between BAAs are feasible. It is still unclear if there will be a similar level of confidence in the zonal transfers when compared to the nodal transfers since no intra-BAA transmission constraints will be considered. PacifiCorp also acknowledges that there is still some diversity benefit if imbalance reserves are procured for each BAA zone, but less than if imbalance reserves are procured using deployment scenarios that consider intra-BAA constraints.



It is important that any new market products or functions can be implemented with the EDAM in a timely fashion. During the DAME stakeholder process, there was concern that a nodal imbalance reserve design was going to be too complex for the CAISO to implement. After hearing discussions at the most recent workshops, it is not clear to PacifiCorp that a zonal design would be any less complex than a nodal design since the CAISO would have to redesign the product for a zonal implementation. This is especially true if the zonal design used sub-BAA zones to procure imbalance reserves. If each BAA was responsible for managing their own zones for the market, it would likely require a lengthy and time-consuming process for each EDAM BAA to decide how to define their zones. At this time, PacifiCorp would not advocate for an imbalance reserve design that requires more responsibilities for EDAM BAAs’ staff, especially since it would need to be done in parallel with EDAM implementation. From the workshop discussions on a zonal design, it sounds like EDAM BAA operators would be tasked with blocking resources from providing imbalance reserves if the resource was likely behind a constraint. While this is not ideal for PacifiCorp, it could be managed. However, in PacifiCorp’s view, while the challenges associated with implementing a zonal design are different than a nodal design, neither design seems to lead to a significantly simpler implementation. As the CAISO has stated, the imbalance reserve implementation will be similar to the nodal FRP.  PacifiCorp believes it is reasonable to assume that the experience the CAISO gained from implementing the nodal FRP will be helpful in implementing a nodal imbalance reserve product.  


Design Consideration – Market Clearing Time

While PacifiCorp generally supports a nodal design, there are key components that need more consideration. First, PacifiCorp is concerned with the processing time for the day-ahead market to clear. At this point, it is unknown how long the day-ahead market will take to clear after the addition of the different market runs needed for EDAM and DAME. If the day-ahead market cannot clear by 1pm, the consequences for EDAM BAAs could be severe. For example, an EDAM BAA could fail to nominate enough gas to cover any incremental capacity awarded after the market results are published. PacifiCorp also realizes that rigorous testing of the market clearing time is not possible before the May Board meetings. For this reason, PacifiCorp advocates for the imbalance reserve design to include some flexibility if it is found that design adds too much complexity to the market clearing process. If necessary, PacifiCorp is open to the CAISO implementing the imbalance reserve product in a similar way to FRP, i.e., not enforcing all transmission constraints in the deployment scenarios at go-live. Furthermore, PacifiCorp would recommend the CAISO delaying the implementation of the downward products if the day-ahead market is not able to clear in the normal timeframe. PacifiCorp views the downward products as products that will add value to the market. However, as the CAISO stated in the stakeholder workshops, the products will likely have more value for reliability in the future as more variable energy resources enter the system. It is PacifiCorp’s position that the market clearing on-time is more important than the downward products for the EDAM go-live.


Design Consideration – Deployment Scenarios

PacifiCorp also has concerns with how the deployment scenarios are currently designed. The issues stem from the challenges of predicting where and how much uncertainty may materialize in real-time. The deployment scenarios could lead to price signals that may not incentivize the flexibility that the system needs. The Day-Ahead Market Enhancements Analysis from January 2022 shows the materialized uncertainty with the amount of imbalance reserves that would have been procured from days in July 2021 and December 2020.[2] The coverage of imbalance reserves to materialized uncertainty was good, but it looks like the deployment scenarios will be overestimating uncertainty much of the time. So, is assuming all the uncertainty in the day-ahead will materialize in real-time a good assumption? This question was raised numerous times during the stakeholder workshops and Market Surveillance Committee (MSC) meetings, and it’s PacifiCorp’s opinion that these questions warrant further discussion. The second concern PacifiCorp has with the deployment scenarios is with the allocation of the uncertainty requirement to individual nodes. PacifiCorp agrees that accurately predicting where on the system uncertainty will materialize is difficult, but also thinks the CAISO could alter the allocation method to better predict where uncertainty will materialize. The Western Power Trading Forum used the example in the workshops of Bakersfield solar contributing less to the uncertainty than coastal solar uncertainty. While PacifiCorp cannot compare the uncertainty needs from WPTF’s example, there are renewable energy generation pockets in PacifiCorp’s system that contribute differently to the uncertainty seen between day-ahead forecasts and real-time output. It is likely that there are other areas across the EDAM footprint that will contribute to the overall uncertainty differently. The variation in uncertainty may also be highly seasonal. Therefore, PacifiCorp requests the CAISO to consider if a geographical and/or seasonal consideration could be included in the uncertainty allocation method.


Design Consideration – Resource Eligibility

PacifiCorp would like to see more discussion on what capacity should be available to bid for imbalance reserves. The CAISO has maintained that imbalance reserves will be capped at the resource’s 15-minute ramping capability, but there were many good points raised during the MSC meeting as to why that may be too limiting. The amount of imbalance reserve capacity available to the market has implications on the value of the product. PacifiCorp believes imbalance reserves should not be an expensive product in the market. Increasing the supply eligible to provide imbalance reserves will help keep the costs of the product down. Some more consideration from the CAISO is appreciated.


Design Consideration – Imbalance Reserve Demand Curves

PacifiCorp would also like to see more discussion on the structure of the demand curves used to procure imbalance reserves. This topic has come up a few times in different MSC meetings, but there has not been much time to fully discuss among stakeholders. The demand curves will have significant EDAM implications on the imbalance reserve capacity that is procured and how it is priced. The DAME Final proposal had the imbalance reserve demand curve modeled after the FRP demand curve. In PacifiCorp’s opinion, the imbalance reserve demand curve should look different than the demand curve for FRP, since scarcity of imbalance reserves is very different than scarcity of FRP. So, PacifiCorp would like there to be robust discussion, preferably with the MSC involved, to determine what appropriate demand curves will be.


Design Consideration – Tunable Parameters

Finally, it is PacifiCorp’s view that the design should include some parameters that can be tuned as the market gains more experience with the imbalance reserve product. PacifiCorp is supportive of the CAISO enforcing only active and base constraints in the deployment scenarios at go-live and increasing the number of constraints modeled in the future. PacifiCorp would also advocate for the CAISO to work with EDAM BAAs to also include any constraints that entities think should be explicitly modeled. Furthermore, PacifiCorp would be supportive of a tunable parameter for the percentage of the uncertainty requirement that is considered in the deployment scenarios. At this time, PacifiCorp believes modeling less than 100% of the uncertainty requirement in the deployment scenarios could be a good way to minimize the price formation concerns the deployment scenarios cause. Since there is not a good way to test the impact imbalance reserves will have on the market, PacifiCorp believes it is important to have some parameters that can be changed to optimize the performance of the imbalance reserve product.



The DAME initiative is a key component of the EDAM.  PacifiCorp is confident that the extended time to consider various aspects of each design and their trade-offs has given the stakeholder community a better understanding of the proposal.  With that said, as described above, significant work remains before the CAISO will be able to meet the goal of bringing a proposal to the WEIM Governing Body and CAISO Board in May. We encourage the CAISO to continue these robust discussions and to remain responsive to stakeholder feedback. PacifiCorp looks forward to working with the CAISO and stakeholders in meeting that goal.



[2] Alderete, Guillermo Bautista and Zhao, Kun. Day-Ahead Market Enhancements Analysis. California ISO. January 24, 2022. Day-AheadMarketEnhancementsAnalysisReport-Jan24-2022.pdf (

Public Generating Pool
Submitted 03/30/2023, 11:16 pm


Sibyl Geiselman (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The Public Generating Pool (PGP) appreciates the opportunity to comment on the DAME Nodal vs Zonal extended stakeholder process to date. PGP also supports some of the changes made in the Final Proposal, including the removal of the attempt to account for energy cost in imbalance reserve procurement, no mitigation for IR down, and the negotiated rate option for IR bids, all of which help to reduce the chance for over-mitigation. These aspects should be carried forward into any Revised Final Proposal. 

The efforts from all stakeholders, particularly WPTF, Vistra, and SCE to bring alternatives to the table and think critically about potential sticking points in the current design have added significant depth to the conversation and to the knowledgebase of the broader stakeholder pool. In addition to stakeholder updates, PGP recognizes the effort from CAISO staff to be responsive to concerns and to continue to consider tradeoffs in the design. The matrix published to compare the potential designs provides a useful outline for feedback on the discussion so far, as does the list of options presented by the MSC. PGP’s view of a viable path forward aligns most with “Option 5” which demonstrates the use of the nodal framework but takes advantage of tools within the modeling process and demand curve structure to address some of our chief concerns about use of the deployment scenarios and market power mitigation impacts.  Hopefully this approach will also avoid catastrophic runtime impacts that may have been inherent to an overly constrained nodal analysis for the procurement.

Basic Description (Product and Process Under Discussion)

PGP recognizes that there are many design aspects in the DAME proposal that are still under revision, but overall continues to support the need for the Day-Ahead Imbalance Reserve product in both directions to enable the system to evolve towards integrating significant amounts of variable energy resources on the system and to reduce market operator actions to increase flexibility on the system. While some of the stakeholder discussion focused on whether IR down product is a necessary addition for the CAISO footprint, we suggest that the CAISO continue to have an EIM/EDAM-level focus on this issue.  Export-constrained regions such as the PNW do see potential value for this “insurance product” to support management of seasonal oversupply during periods of constrained flexibility on the hydro system. If this product truly has little value within the CAISO, or this premise proves incorrect, then it will likely be priced very low, but this is not a sufficient argument for removing the product and changing the scope of the IR product definition at this phase, particularly as the CAISO works to prepare for the EDAM and to align products with the broader market design.

PGP recommends the CAISO continue with the design refinement conversation and limit the scope of this effort to avoid re-arbitrating the need for the product and the broader definition thereof. PGP also recognizes that experience with the FRP implementation is directly relevant to the IR procurement design, and that zonal designs of like products in other markets have faced similar deliverability challenges. Based on this experience, PGP agrees with the MSC’s opinion that it is important that any option considered falls withing the capabilities of the nodal design or slight elaborations thereof. PGP recommends that the ideal design is a nodal procurement framework with some modest design changes where they improve efficiency and/or address specific issues raised by stakeholders, as documented in the “design ideas” category at the end of the table.

Uncertainty Calculations/Diversity Benefit

WPTF did an excellent job of outlining a specific concern relating to the allocation of uncertainty across the CAISO footprint for nodal procurement. While these concerns seem very applicable for a large BAA such as the CAISO, where geographical variations in the contributions to uncertainty may be more extreme, they may be less relevant for smaller BA footprints elsewhere in the EIM/potential EDAM footprint. The deep dives on the nodal allocation of the uncertainty in large systems, and the discussion of the diversity benefit in the zonal approach seemed to indicate the potential for misallocation of the diversity benefit in some regions (or proposed zones) within the CAISO system or other large BA footprints. If this is indeed the result of the current allocation of the uncertainty to the nodes, this could create an uneven playing field for market participants in the EDAM, and should be addressed in the design.

To address this concern within a nodal approach, PGP recommends monitoring to ensure the diversity benefit is equitably applied and does not cause insufficient procurement of IR. Alternatively, given the “tuneability” of the nodal approach, as an alternative to the zonal approach, a revised DAME proposal could consider a hybrid approach such as the one discussed in response to WPTF’s presentation, which would be to impose a zonal layer for allocation of diversity benefits within the BA footprints that are large enough to experience material impacts due to the mapping to the nodes. While it was observed that this product will be procured differently than ancillary services, perhaps systems that are large enough to require AS zones would be a reasonable threshold for consideration. This should address the concerns raised by WPTF, while building upon existing frameworks to move the design forward and preserving the optionality to remove this layer later. In the broader RSE/EDAM framework, this would also preserve the BA as the fundamental building block which is important for the overall market design.

Regarding the discussion around a combined net load analysis, if the Quantile Regression Approach performs as intended, having data to support load, wind and solar individual contributions to the procurement requirements is helpful information, and may provide useful insights for BAs in terms of planning and in analyzing expectations of the evolution of system needs. This may also be a useful dataset for cost allocation methodology development.

In reference to the broader dialogue around the procurement scenarios forcing the assumption of uncertainty that “will never materialize,” Dr. Scott Harvey’s MSC presentation discussing the implications of the methodology outlined by CAISO’s current “Option 1” showed that allocation of the diversity benefit results in deployment scenarios that are not nearly the extremes described by some stakeholders and that this is an improvement on procurement of flexibility through the use of load conformance. PGP supports the continued alignment of this product with the broader EDAM design and ongoing reliance on lessons learned through FRP implementation thus far. We also observe that a functional nodal model is one that will essentially create dynamic zones based on the deliverability scenarios net of diversity allocation, which seems preferable from an efficiency and accuracy perspective to seasonal or otherwise stagnant zonal configuration analysis.

Transmission constraint enforcements and Implications/Market performance impacts

PGP appreciated the detailed discussion of the deliverability analysis at the MSC and the tradeoffs between different approaches. The experiential learnings from FRP implementation and tuneability of the nodal approach seem to indicate that it has sufficient flexibility to avoid over-constraining the solution or over-paying for small gains in IR procurement efficiency. The MSC noted (Zonal IBR Design Presentation from March 10, pg.4) that they are not aware of any adverse solution time impacts from the FRP design, though little was said in the workshops regarding the anticipated challenges with runtime and problem size in the EDAM with the IBR product nodal procurement concept. PGP recommends further exploration of this issue to determine if simplifications or removal of some constraints may be required purely from a practical implementation perspective. To alleviate concerns, further analysis of the FRP nodal procurement as more data is available, and “loose mitigation” at the onset of the IR product rollout will support the CAISO’s ability to tune the nodal procurement while mitigating the concerns from the use of the deployment scenarios. PGP also recommends further exploration of including lower penalty prices in the nodal IR procurement to reduce the enforcement of constraints in the procurement and the likelihood of congestion, overpaying for the product, and/or market power mitigation impacts. AS CAISO and participants gain experience, additional constraints could be enforced over time as appropriate. A successful implementation of this should capture some of the benefits of a zonal approach, while helping to reduce solve times.

Which DAM process procures Imbalance Reserves?/Virtual bidding impact

PGP supports a design that procures IR through the IFM, separately from the RUC process.From the perspective of potential EDAM participants, the product as defined by the CAISO including net load uncertainty vs forecast, rather than differences between physical vs financial commitments (handled by RUC) is an important distinction, given the potential for differences in virtual participation frameworks for EDAM entities, the interaction between the RUC process and various RA programs, and the interaction of the IR uncertainty calculation and the DA RSE in EDAM. As such, while PGP appreciates the spirit of efficiency reflected in the SCE approach, the concerns that it introduces and the influence on overall product definition and benefits proposition is not reasonable to entertain at this phase in the market design.

Need for Market Power Mitigation

Excessive market power mitigation due to the nodal IR deployment scenarios was one of the chief concerns raised by PGP in our prior comments. We support the design changes introduced in the Final Proposal that may help to address this issue, and to further alleviate this risk PGP recommends the CAISO pursue a nodal design that initially enforces fewer constraints and reduces penalty factors to help avoid systemic over-mitigation, and careful monitoring of required mitigation after implementation in case this issue needs to be revisited. Additional analysis of the FRP procurement and robustness of suppliers of this product may also help to alleviate concerns in this area. Further discussion of revisions to the market power mitigation framework in areas outside of the CAISO is also expected to occur in the Price Formation Enhancements initiative, and PGP would appreciate additional discussion of how those revisions may impact the need for Market Power Mitigation of the IR product.

Price Formation (Imbalance Reserves)

PGP recommends additional examples similar to those discussed in the price formation enhancements workshop and further discussion of the IR demand curve at a future meeting.

Price formation (energy)/ Congestion revenue impact

PGP challenges some of the assertions that DA congestion due to uncertainty is an incorrect price signal. Given that VERs are a direct cause of the additional need for the IR product, it does not seem wholly inaccurate that the “mere potential for congestion” driven by this uncertainty translate into the DA price. PGP recommends that the final design consider that some EDAM BAAs may not structure the congestion rent allocation in the same way as the CAISO, so the approach to correct for under-funded CRRs due to the deployment scenarios may be more appropriately managed at the BA-level and may not need to apply across the entire EDAM footprint. This differentiation should be clear in any final design so that the solution within the CAISO can effectively meet the needs of current CAISO market participants.

Confidence in EDAM transfers/Enablement of transfers

Throughout the EDAM design process, many stakeholders expressed a high level of concern regarding deliverability risk in the RSE. PGP appreciates that the nodal IR design helps address this issue. Experience with the FRP also reiterates that deliverability is better accounted for in a nodal design, and we support building upon the learnings through that product development.

Connection to the EDAM RSE/Enables diversity benefit

The documentation of the tradeoffs associated with the zonal approach seems to align best with the idea of splitting a larger BA into smaller areas (thus potentially increasing the RSE requirement) but fails to contemplate there may be efficiency gains or seams issues that could be managed through the option to combine RS tests, for example for participants that are part of the same RA program.  The latter optionality may be a consideration in any seams analysis and could potentially be added as part of implementation agreements as more entities join. PGP recommends this concept be explored further to enhance the “RS as the universal adapter of RA programs” concept as seams issues and interoperability challenges are better understood. For completeness, the table could be updated to more clearly consider the case of combining BAs to form a zone and the corresponding impacts to the diversity benefit of this approach.

That said, maintaining the EDAM RSE design is an important consideration at this phase, so as not to derail the timing of the EDAM initiative, and PGP recommends maintaining the BA as the fundamental building block for now, with further documentation and publication of the diversity benefit contribution and calculations as part of the implementation phase for EDAM entities. Something akin to the zonal benefit for combining BAs for the test is already established with the diversity benefit allocation and pooled WEIM test, however mapping to individual entities would likely still be required in any zonal approach if BAs were combined to create zones for the IR product. This design effort seems unrealistic to address without undermining the timing of the EDAM initiative.

Co-optimization benefit

PGP supports market efficiency and transparency, including direct co-optimization.

Consistency with FRP

PGP recommends any final proposal works to address the concerns voiced by the MSC and others based on calculating this product purely on the fifteen minute ramp capability. If this issue is adequately addressed through the co-optimization and IR requirements calculation, further examples may be required to demonstrate this. To the extent feasible, PGP sees benefits in maintaining consistency across the products.

Operator confidence and intervention

Some stakeholders have questioned the need for this product, and some have proposed modifications such as the factor reduction of the deployment scenarios that water down the product and undermine its transparency, suggesting that the system needs are being met effectively with the current process. While this may be the case for the CAISO RTO as a stand-alone market, for parties that have concerns about the lack of a standardized RA program across the EDAM footprint, the EDAM RSE (including uncertainty) as the universal adapter of RA programs across the broader participant pool is a critical component of the EDAM design.  Repeated Market Operator actions to fulfill BA obligations create price distortions within the EIM market, reduce price formation transparency, and have an unknown but high cost of undermining the regional trust in the CAISO as the MO for a regional market. The inability to reduce these actions by the MO for the CAISO BA puts the potential benefits of the DA market at risk. PGP suggests that under the EDAM framework, additional work needs to be done to differentiate the roles of the CAISO as EIM/EDAM Market Operator and the CAISO Balancing Authority more effectively, and that stakeholders focus on this distinction as it pertains to the BAs as the building blocks for the Extended Day Ahead Market. Those who want an ultimately successful and robust Extended Day Ahead Market should consider that the unknown cost of the current process and reliance on market interventions is not isolated to direct and short-term cost, and it is certainly not zero. PGP looks forward to any additional analysis on the hidden cost of the current approach that may provide additional insight for those who still have concerns about the introduction of this product.

Cost allocation and settlement impact

The benefits of the BA as the building block is an important consideration in this category, and the nodal approach appears to align better with that objective.

Implementation risk, timeline risk

PGP has found this exercise to be extremely valuable and supports a modified nodal approach that addresses our chief concerns of the risk of over mitigation while building on the current design so as not to undermine the EDAM implementation timeline. PGP had requested analysis of the zonal approach, and we have also researched other markets for functional examples of a like product, and unfortunately were unable to find a functional zonal example. The experience gained in the FRP process has been helpful and should continue to be reported on. For some analysis of a zonal approach, PGP recommends stakeholders review the recent SPP MMU report on their Day Ahead Ramp Capability Product, which indicated similar deliverability challenges to those experienced with the Zonal FRP. See “special issues” pg. 62: mmu quarterly state of the market report summer 2022.pdf

Potential design modifications to address concerns with approach

We support the approach of building on the nodal design with reduced constraint enforcement and lower penalty prices, along with the aspects of the Current Final Proposal that reduce the likelihood of over-mitigation. Further documentation of the anticipated impacts of any design changes on expected MPM would add value to any revised final proposal. PGP expects that monitoring and reporting on mitigation should help to indicate if any issues with supply or price are arising so that it can be further addressed in the design if required.

PGP also recommends that the impacts of the diversity benefit allocation be better understood before any additional parameters be added to reduce the quantity of imbalance reserves that is tested for deliverability, especially given the analysis provided by the MSC indicating this is an unlikely area for gaming from virtual participants, and we do not support that modification proposal at this time.


PGP recommends further consideration be given to how the Imbalance Reserve demand curve relates to the RSE failure penalty structure, as this penalty represents a ceiling for what BAs should be willing to pay for IR. PGP recommends an analysis of whether there is a disconnect in the design in this regard, and further dialogue on the demand curve structure or flexibility in the design may be required to move the initiative forward while maintaining the desired timeline.


The comparison table and dialogue at the MSC provided clear documentation of the tradeoffs between the nodal and zonal approach. This discussion and extended stakeholder process has supported the potential to develop a nodal approach that addresses the outstanding concerns of stakeholders and captures some of the benefits of a zonal approach. PGP also sees room for additional analysis to address the uncertainty mapping concerns for large BA footprints but recognizes these concerns may not be applicable to all potential EDAM entities.  PGP looks forward to seeing a revised proposal that reflects this compromise and continues to align with the broader EDAM design.




Public Power Council
Submitted 03/30/2023, 03:46 pm


Michael Linn (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The Public Power Council[1] (PPC) appreciates the opportunity to provide comments on the Day-Ahead Market Enhancements stakeholder workshops that have taken place since the release of the Final Proposal.  PPC appreciates the opportunity CAISO has provided for additional discussion and the stakeholders that have prepared additional material and proposals.  These workshops have provided valuable dialogue on the trade-offs between 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 resources to provide flexible capacity.

PPC believes CAISO staff has clearly articulated the need for, and the benefits provided by the Day-Ahead Market Enhancements for years now.  The challenges CAISO faces managing the increasing number of variable resources with the existing day-ahead market design and products have been well documented throughout this stakeholder process and other CAISO reports.  Operators have been routinely relying on out-of-market actions such as load conformance and exceptional dispatch to set up the CAISO BAA with sufficient flexible capacity to reliably meet real-time operating conditions. The regular reliance on out-of-market actions is inefficient and undermines the economic signals provided by market prices.  While PPC maintains the original market formulation that would have combined IFM and RUC into a single co-optimized market run was a superior foundation for EDAM, PPC still believes creation of the imbalance reserve product is critical to the success and functioning of EDAM.  The implementation of a well designed imbalance reserve product is also a signal to potential EDAM participants that CAISO is willing to implement changes to its market and not continue to rely on substantial out-of-market actions. 

PPC believes at this stage of DAME proposal development there should be a narrow scope of potential changes from the published final proposal.  CAISO has spent years developing the imbalance reserve products and significant modifications to DAME at this point would necessitate additional discussion beyond what a May board meeting timeline would allow.  PPC believes it would be inappropriate to make significant changes at this stage such as moving the procurement of imbalance reserves into the residual unit commitment process.  This modification would significantly alter and undermine the intended purpose of imbalance reserves and have potentially large implications on EDAM.  PPC believes if the CAISO were to pursue this path, far more stakeholder discussion on DAME and EDAM would be needed.  The removal of the imbalance reserve down product from the scope of DAME would also create the need more discussion.  This product may have value to Northwest entities managing hydro systems.  PPC believes CAISO staff should weigh in on the degree to which the removal of this product would reduce the complexity and computational requirements of the day-ahead optimization.

Nodal vs Zonal Procurement

The imbalance reserve products are designed to cover day-ahead to real-time net-load uncertainty and as such PPC understands the products will be regularly dispatched in the operating day.  PPC also understands there may be periods where significant amounts of imblanace reserves are needed.  Further, in EDAM the pooled diversity benefit will lower the total capacity need of the EDAM footprint and EDAM entities may regularly rely on imbalance reserves held in other EDAM entity BAAs to cover uncertainty and potentially decommit resources.  These factors support the need for high confidence that the imbalance reserves procured in day-ahead are in fact deliverable in real-time.  PPC believes it would be valuable for CAISO to elaborate on how and to what degree a zonal approach would reduce deliverability of imbalance reserves. Currently, PPC generally supports beginning with a nodal approach to imabalance reserves and relaxing less important transmission constraints if necessary.

PPC does not agree that capacity deployment scenarios creating transmission congestion is inappropriate.  If transmission transfer capacity is limited to ensure deliverability of capacity, it does not seem innappropriate that this use of the transmission system is reflected in congestion.  As the west continues to integrate renewable resources it is likely these types of uses of the transmission system will become more common and important.  Ensuring the market communicates this information through prices at a nodal level may be valuable to market participants moving forward.

Market Power Mitigation

PPC remains concerned the degree to which market power mitigation is embedded in the DAME design will deter flexible resources from offering imbalance reserves.  While PPC supports some modifications made in the final proposal such as not mitigating imbalance reserve down prices, PPC remains concerned with the overall degree of market power mitigation.  PPC suggests CAISO should re-examine if market power mitigation is necessary in the deployment scenarios.  Further, CAISO should explore calculating the default availability bid based on high percentile at an hourly granularity as there may be significant differences between the evening net-load peak and other hours of the day.



[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.


Public Utilities Commission
Submitted 04/05/2023, 03:53 pm


Philip Voris (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

CPUC Energy Division staff (hereinafter ED staff) appreciates the opportunity to comment on 1) CAISO’s Day-Ahead Market Enhancements (DAME) Draft Final proposal, 2) issues raised during the workshops held on February 27 and March 7-8, and 3) discussions at the Market Surveillance Committee meeting on March 10, 2023.


Based on ED staff’s review of the proposal, presentations, and discussions, ED staff provides the following comments consistent with comments provided throughout the process:


  • DAME Costs.  ED staff remains concerned about the high potential for additional costs that could be imposed on California customers as a result of CAISO’s proposed introduction of two new products – the Imbalance Reserve (IR) product and the Reliability Capacity (RC) product.  Currently, CAISO commits additional capacity in its Residual Unit Commitment (RUC) process, but most of the additional capacity is resource adequacy (RA) capacity that is required to bid into the RUC at a $0 bid.  Thus, there is typically very little additional costs associated with the additional commitment through the RUC process. For example, CAISO’s Department of Market Monitoring (DMM) reports that RUC payments were less than $100,000 in most months and approached $400,000 in December of 2022 (see figure below).[1] By contrast, with the introduction of these two new products, CAISO customers would be required to pay for the IR and RC products at the market clearing prices and we expect that this could result in tens, if not hundreds of millions in payments by California customers, with no corresponding increased reliability or other benefit.[2] For example, if CAISO is required to procure 4,000 MW each hour, based on the day-ahead imbalances shown in the figure below,[3] this would result in $17.5 million at a price of $0.5/MWh, $175 million per year at a price of $5/MWh, but $1.75 billion at a price of $50/MWh. As noted by CAISO’s DMM, ancillary service costs exceeded $200 million 2022 and if IR and RC approach these levels, this could increase costs substantially for California customers.  In its draft final proposal, CAISO predicts that the increased energy market costs for California customers will be offset by decreases in capacity payments, but California customers have signed billions of dollars of long-term contracts which will be difficult, if not impossible to renegotiate.  Further, it is unlikely that any party will be able to estimate expected revenues associated with these products when CAISO is unable to estimate the prices that will clear the market and/or provide an estimate of the additional costs to customers.  Further, parties do not have sufficient data to estimate future expected revenue streams with any certainty, given this is a new product, and it will take years to understand how it performs in the market.  Thus, ED staff does not believe capacity payments will decrease in anticipation of IR and RC payments for years, if at all, given current long-term contracts as well as the uncertainty surrounding specification and implementation of these four new products (including IR and RC up and down).







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  • DAME Revenue Return.  ED staff has requested that CAISO facilitate a process for the return of these revenues and CAISO initially agreed to a 50/50 return of IR payments and 100 percent return of RC payments, but reversed course this past November and now proposes no return of these payments and that CAISO will only facilitate information sharing between willing parties. 


ED staff’s understanding is that CAISO will provide data regarding these payments to LSEs that own the RA capacity only if the generator agrees to such data sharing.  This will increase transaction/administrative costs and will likely result in a proliferation of disputes and lawsuits regarding these payments, further increasing costs to California customers, again with no corresponding or identifiable benefit. These concerns need to be addressed in order to ensure that California ratepayers do not incur significant additional costs.  The intent of moving these market efforts forward is to provide more reliability and lower cost, therefore additional work is needed to adjust the proposal to ensure that the result does not unnecessarily increase costs for California ratepayers.


  • DAME Downward IR and RC Products. As noted by numerous parties during the workshop, CAISO has not made a clear case for a downward IR or RC product. It was ED staff’s understanding that one benefit of EIM (and EDAM) is to reduce curtailment of exports and it seems duplicative to also pay resources for their ability to ramp down, given no identifiable issue with downward ramping capability.  Further, IOUs and others have renegotiated contracts to allow for renewable curtailment.  Finally, given the flexible capacity product and the corresponding real-time must offer obligation, the IR and RC downward capacity payments are again duplicative and likely to raise costs for California customers.

    This is illustrated in the following figure, showing that most of the operator adjustments occur in the upward direction and primarily during the summer months – that is, months in which downward adjustments are not typically necessary.  Further, even in those months when one would expect downward adjustments (e.g., the spring), operators do not appear to make downward adjustments, on average.[4]




  • IR and RC Bid Caps.  ED staff is concerned with the bid caps for the IR and RC products, which CAISO proposes to be set at $1,000/MWh.  This is substantially greater than the bid cap for ancillary services, which is $250/MWh.  CAISO has not provided sufficient rationale for the disconnect between these two products.  If the CAISO market cleared 4000 MW IR or RC at a bid cap of $1,000/MWh for 1 hour, this would result in additional payments of $4 million per hour, $40 million for 10 hours, and $400 million for 100 hours. This represents considerable upside cost pressure for California customers on a product they currently do not have to pay for, since, as discussed previously, under the current paradigm the RA RUC bids are required to be zero, and RUC payments for this same commitment of additional capacity are largely de minimis.  Notably, ancillary service costs exceeded $200 million in 2022, with a bid cap at $250/MWh, and ED staff is concerned that with a bid cap of $1,000/MWh, these additional IR and RC costs could be significantly higher.


  • IR Penalty Parameters.  Consistent with comments made during the Market Surveillance Committee meeting, ED staff is concerned about the penalty parameters in the scheduling run for IR products. In particular, ED staff understood that CAISO staff indicated that the penalty parameter in the scheduling run would be higher for low priority exports than for IR capacity, with the rationale being that CAISO could cut low priority exports in the real-time, if necessary to ensure reliability.  In order for parties to better understand how these products will be fully optimized and scheduled in the CAISO market, ED staff requests that CAISO publish all of the penalty parameters that it intends to change as a result of this initiative. ED staff, if its understanding is correct, is very concerned about prioritizing low priority exports over IR capacity, given that the entire purpose of the IR product in EDAM is to ensure CAISO does not transfer excess resources out of its system in the day-ahead market.

    Further, given CAISO’s reluctance to cut low priority exports that have cleared the market (see CAISO’s RSE proposal to include day-ahead cleared low priority exports in CAISO’s RSE), ED staff is concerned that CAISO may be moving in a direction that could put the system at risk by foregoing IR capacity to clear these low priority exports.  Foregoing IR capacity to clear low priority exports could potentially cause CAISO to fail or contribute to CAISO’s WEIM RSE failure, thus creating adverse consequences as to reliability and costs for California ratepayers.  This issue requires further consideration and discussion, after CAISO has published its proposed penalty parameters and stakeholders have sufficient time to discuss this with CAISO and others.


  • Storage Not Counting as Reliability Capacity.  ED staff is concerned that CAISO’s recent proposal to not count storage capacity in the RUC/RC process will lead to higher costs for California customers because CAISO will over-procure RC capacity in the RUC at the market clearing price. For example, if 4,000 MW of storage is not picked up for energy or IR, and is not considered for RC, but still has a real-time must offer obligation as RA capacity, ED staff is concerned that this would result in an over-procurement of 4,000 MW of capacity, at considerable cost to California customers, especially as additional storage resources are brought online.  To illustrate, if RC costs $0.5/MWh and CAISO over-procures RC by 4,000 MW, this could result in additional costs on the order of $17.5 million per year and reduce prices in the real-time market (but if IR is priced similar to ancillary services these costs could be considerably higher, as discussed above).  In addition, in conjunction with EDAM, ED staff wonders why IR storage capacity has a must-offer into the RC market if it will not count toward RC – there appears to be some inconsistency that ED staff does not fully understand. It would be helpful if CAISO could explain this policy and how it results in efficiencies and cost reductions for California customers.


  • IR and RC Reliability Concerns.  ED staff is concerned that the new IR and RC products could increase reliability concerns because it will not cover all of the uncertainty and, thus, it will over-procure likely when the system does not need the capacity and under-procure it when the system needs it most.  As illustrated in the figure above, it is clear that CAISO makes operator adjustments primarily in the summer months and those are the times that CAISO is likely to under-procure the capacity since it is only procuring for a 95% confidence level. If CAISO fails to use the net export constraint to prevent CAISO from exporting the remaining capacity during summer conditions, which could be in the form of transfers that CAISO will support equal to its own load, CAISO could exacerbate reliability conditions if, for example, an intertie went down and it was no longer able to cut transfers in the real-time.  This is further illustrated in the following figure, which shows that on high load days (in blue), the IR product will cover less than 100 percent of the RUC adjustment and in many cases may only cover 50 percent of the RUC adjustment. If RUC adjustments are primarily to ensure reliability, it does not appear that the IR product will sufficiently ensure reliability in the same manner as the RUC adjustments currently function.


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  • IR Product Needing to Be Fifteen Minute Dispatchable. As raised by the Market Surveillance Committee and DMM, among other stakeholders, ED staff is concerned that requiring the IR product to be 15 minute dispatchable is overly restrictive and could limit the pool of resources that can qualify for this product.  As a result of this potentially unnecessary scarcity, it could increase costs even further for CAISO’s customers.


  • Issues with CAISO’s IR Zonal Proposal, Effect on Prices and Transmission Congestion. As raised by numerous stakeholders, ED staff is concerned with two aspects of CAISO’s nodal approach to procurement of imbalance reserves. First, as ED staff understands it, CAISO will model the IR capacity product to ensure that it is deliverable as energy and that this run will establish prices with this congestion, even though this congestion may not show up in real-time (as most of the time this uncertainty will not arise).  This will likely increase prices or at least result in inaccurate prices that are not likely to materialize in the real-time market, which could result in a certain amount of gaming.  Second, as ED staff understand it, modeling capacity congestion will likely result in under-recovery of congestion rents and, as a result, CAISO proposes to allocate this potential under-recovery to all load – again, potentially increasing costs for CAISO’s customers.  For these reasons, ED staff supports SCE’s proposal to include this uncertainty in the RUC process.


  • Settlement different than forecast.  CAISO is measuring the uncertainty in the net load forecast from CAISO’s forecast of day-ahead net load to actual net load and is measuring the uncertainty in variable resources based on CAISO’s forecast of variable resources compared to the actual performance of these resources.  On the other hand, CAISO proposes to allocate the costs of the imbalance reserve product to generation, load, imports and exports based on deviations from their day-ahead schedules. ED staff has not yet determined the effect of allocating costs is a manner different than the cost determinants, but will explore this further before CAISO’s tariff filing.


  • Joint Authority.  Even though CAISO notes that “this initiative would fall mostly outside the authority of the WEIM Governing Body because it focuses on the day-ahead market,” CAISO here proposes joint authority for all aspects of the proposal.


ED staff is concerned about this recommendation because this initiative will affect penalty parameters, which affect reliability for California customers (e.g., what penalty parameter does IR get compared to low priority exports).  Further, if EDAM does not materialize, these provisions will apply only to CAISO customers. Therefore, at this point in time, ED staff does not support the joint authority model in this instance, given the critical importance that this initiative will have on reliability for California customers and that WEIM entities are not yet part of the day-ahead market.


ED Staff Recommendations.  ED staff 1) supports SCE’s proposal to include the uncertainty in the RUC process, 2) supports suggestions to allow hourly deliverable product to address uncertainty, and 3) supports reducing the bid cap for IR to at least $250/MWh and perhaps as low as $50/MWh, as suggested by some stakeholders, 4) supports excluding the downward product from this proposal, 5) supports CAISO publishing the penalty parameters resulting from this initiative 6) supports inclusion of storage capacity in the RUC process, and 7) does not support CAISO’s joint authority proposal.



[1] 2022-Fourth-Quarter-Report-on-Market-Issues-and-Performance-Mar-16-2023.pdf (, p. 25.

[2] Id. at p. 27.

[3] Day-AheadMarketEnhancementsAnalysisReport-Jan24-2022.pdf (, p. 7.

[4] 2022-Fourth-Quarter-Report-on-Market-Issues-and-Performance-Mar-16-2023.pdf (, p. 24.

Puget Sound Energy
Submitted 03/30/2023, 12:47 pm


Jessica Lam (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

See attached.

Sacramento Municipal Utility District
Submitted 03/31/2023, 12:25 pm


Andrew Meditz (andrew.meditz@smud)

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The Sacramento Municipal Utility District (SMUD) provides these comments on the CAISO’s Day-Ahead Market Enhancements (DAME) initiative following the three recent workshops. SMUD is an active participant in the CAISO’s day-ahead and real-time markets over the interties. In addition, SMUD currently participates in the Western Energy Imbalance Market (EIM) through the Balancing Authority of Northern California and is participating in the Extended Day-Ahead Market (EDAM) initiative. Accordingly, SMUD has a direct interest in this initiative from both a market and reliability perspective.


SMUD supports the overall DAME concept as improvements are needed to both market efficiency and reliability to address the ever-increasing variability of supply (e.g. wind and solar) throughout the West. Specifically, as to the Imbalance Reserves proposal, this product is an important component to balance the system and reduce reliance on the Residual Unit Commitment (RUC) process and out-of-market actions, which are limited tools and can cause inefficient market results.  As discussed at the workshops, there are three options to procuring Imbalance Reserves – 1) Nodal Approach, 2) Zonal Approach, and 3) SCE Approach (RUC Process).


While each of the three approaches appear to be viable options to procure Imbalance Reserves, SMUD considers the Nodal Approach to be the most efficient co-optimization of energy and Imbalance Reserves that ensures both products are feasible at time of procurement. We appreciate the workshop presentations and discussions around the different approaches, but we did not hear a compelling concern about the Nodal Approach, nor a convincing reason to switch to the Zonal Approach or SCE Approach. The Nodal Approach to procure Imbalance Reserves is analogous to the Flexible Ramping Product which serves a similar purpose for the Real-Time Market. Moreover, SMUD sees the Nodal Approach aligning better with EDAM by calculating uncertainty requirements at the Balancing Authority Area level. And as a load-serving entity, reasonable market power mitigation is a critical feature to safeguard our customers against market power by participants. Accordingly, SMUD supports the Nodal Approach, subject to a few caveats as outlined below.


While the Nodal Approach puts the DAME on the right track to efficiently procure Imbalance Reserves, it is imperative that the CAISO allow flexibility to accommodate modifications, if necessary.  During implementation of DAME and after go-live, we encourage the CAISO to perform robust testing and evaluation of the Nodal Approach. It is important that the CAISO monitor and gather data on the market’s performance to determine whether refinements are needed to the nodal Imbalance Reserve design. Specifically, the CAISO should allow flexibility to make adjustments to such things as the uncertainty allocation to BAAs, demand curve values, which constraints to enforce, deployment scenario modeling, and start-up/ramping capabilities of resources. For example, if the CAISO’s DAME implementation unreasonably impacts EDAM implementation timing or if the CAISO observes a material pricing divergence between the Day-Ahead Market and Real-Time Market, the CAISO should have the ability to modify market parameters.


Thank you

Seattle City Light
Submitted 03/30/2023, 04:26 pm


Stefanie Johnson (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

Seattle City Light (Seattle) appreciates that the CAISO has allowed additional time for continued conversation and vetting of alternative approaches in response to stakeholder concerns with certain aspects of the Final Proposal. Through these additional workshops and meetings the community has had the opportunity to consider alternatives and are now better prepared to make a more informed determination about the best fit for the Day Ahead Market Enhancements.

Seattle City Light largely supports the CAISO’s Final Proposal with some minor areas to consider revisiting. First and foremost, Seattle supports retaining nodal procurement of both up and down imbalance reserves. With Seattle being a predominantly hydro system with minimum generation requirements, the downward IR product is a necessary feature. The nodal approach provides flexibility to “scale up” in complexity with, for example, modeled contingencies post-implementation, but allows for starting simply with deployment scenarios without contingencies or nomograms. Using a design that is better able to evolve as the market does is a stronger option long-term.

Zonal procurement could mask many potential issues with deliverability, zone definitions, price formation, and market power mitigation. A nodal approach is less burdensome to implement and maintain, from both a staffing perspective for the ISO and EDAM participant entities, which are important factors for Seattle. Nodal also better meshes with FRP design and settlement, both in the use of nodal procurement and symmetrical up/down products. However, as stakeholders highlighted, aspects of a nodal approach may require fine tuning; Seattle urges CAISO to monitor impacts to Ancillary Service awards, CRRs, and the interplay with virtual bidding. Despite these areas that may require monitoring, the flexibility, scalability, and lesser staff maintenance burden of a nodal model outweigh potential imperfections for Seattle.

Additional areas where Seattle would appreciate greater focus are in Market Power Mitigation and the procurement of 15-minute ramp capability. With regard to Market Power Mitigation, whether DAME ends up with a nodal or zonal model, close monitoring and swift action post-implementation is warranted. The second area that would benefit from additional consideration highlighted by the MSC, is the procurement of 15-minute ramp capability. Considering that the bulk of uncertainty is foreseen multiple hours ahead of real-time begs the question of how much of that uncertainty translates into a 15-minute ramp requirement versus an hourly ramp need .  Either reducing the IR requirement or relaxing the demand curve in Day Ahead could mitigate potential over-procurement.

Seattle would support a follow up initiative to consider a more robust long-term solution which could include a separate 15-minute and hourly product, or a 15-minute product with a separated 15-minute requirement and an hourly requirement with the latter calculated but not procured in day-ahead. In the interim Seattle is supportive of including the proposed 15-minute ramp product and urges the CAISO to address future needs and assess the product’s success post EDAM implementation.


Six Cities
Submitted 03/30/2023, 05:32 pm

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


Margaret McNaul (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

The Six Cities acknowledge and appreciate the additional time that the CAISO and stakeholders have dedicated over the past month to evaluating alternatives to certain elements of the Day Ahead Market Enhancements (“DAME”) Draft Final Proposal, including, in particular, the use of “zones” for procurement of imbalance reserves (“IR”) in lieu of procurement on a nodal basis, as proposed by the CAISO.  The Six Cities also note the efforts of the CAISO to provide additional information regarding its preferred approach. 

While the discussion at the workshops and the March 10th Market Surveillance Committee (“MSC”) meeting was robust and demonstrated a high degree of stakeholder engagement on these topics, it is less clear that there is consensus around any single alternative approach—or set of approaches—to the CAISO’s preferred IR product design.  As was frequently observed during the workshops, the alternatives all provide different benefits and have different tradeoffs.  While it is not clear that there is any one methodology for determining IR needs and designing IR procurement that has emerged as inherently superior, pivoting to a zonal methodology for determining IR requirements and for IR procurement does appear to entail some risks that are not present, or are present perhaps to a lesser degree, with a nodal approach. 

It is also clear that the CAISO’s timeline for the remainder of this initiative is not adequate to allow for a complete analysis of each and every possible design choice, and, as discussed at the MSC meeting, there are many options that could be considered.  While the Six Cities believe that the assessment of several alternatives would likely benefit from additional discussion in the Revised Draft Final Proposal, it is not realistic for the CAISO and stakeholders to undertake a complete analysis of the options that have been discussed between now and May, when the CAISO intends to take a Final Proposal to the Board of Governors and EIM Governing Body for approval.  Even if the CAISO were to extend this initiative by several additional months or even through the end of the year, it is not certain that stakeholder consensus around zonal versus nodal IR procurement and all of the associated design elements would be achievable.  Nevertheless, confidence in the DAME market design could be enhanced if there were additional time allotted for simulation and study of the design options under consideration. 

With the foregoing in mind, the Six Cities have formulated their comments to support further consideration of potential design variations that appear to be the most viable and/or seemingly represent incremental improvements relative to the CAISO’s preferred design for nodal IR procurement, including several of the “options” discussed at the MSC meeting. 

  • First, the Six Cities note the CAISO’s further explanations of the basis for its current “nodal” design for IR, which includes a balancing authority area (“BAA”) determination of uncertainty that is distributed based on forecasts to load, solar, and wind nodes, and nodal procurement of IR based on deployment scenarios.  This explanation has been helpful in understanding the CAISO’s market design. 
  • Second, on the topic of nodal IR design and potential alternatives, the MSC has highlighted some of the benefits and tradeoffs of a nodal design approach (i.e., Option 1 of the MSC presentation).  Broadly speaking, the nodal design appears to carry some risks, several of which appear to be capable of mitigation through appropriate calibration of penalty prices.  On the other hand, the MSC’s observations that several zonal design options raise “[s]erious market power issues” in addition to continued deliverability problems, diminished pricing transparency, and challenges with implementation and complexity, are compelling.  The MSC’s findings weigh in favor of rejecting the “zonal” alternatives that include both a zonal IR requirement and zonal or contract path procurement, which the Six Cities understand to be represented by the MSC’s Options 2 and 3.  The Six Cities also ask the CAISO to further assess the viability of the other variations of nodal IR design that were under discussion during the MSC meeting and consider if these would represent improvements over the CAISO’s preferred design (or reflect its current intended approach), including MSC Options 4 and 5 (and the associated variations on these designs represented by Options 6 through 10). 
  • Third, despite the findings of the MSC, some proponents of a zonal approach have highlighted the risk of imprecise and/or excessive IR procurement and increased costs and complexity resulting from the nodal approach.  If the CAISO decides to proceed with a nodal design for IR and as the market gains experience with nodal flexible ramping product (“FRP”), it would be useful for the CAISO and stakeholders to have some ability to refine the IR design in response to any feedback or lessons learned from FRP.  What steps would the CAISO take to ensure that its IR design can be adjusted as the CAISO gains experience with nodal FRP?
  • Fourth, the Six Cities urge the CAISO to consider the formulation of the penalty prices applicable to IR, consistent with the discussion during the MSC meeting. 
  • Fifth, with respect to the ongoing discussion about whether there is a need for a downward IR product, the Six Cities do not find generic assertions of perceived “FERC risk” due to a purported lack of need for this product to be particularly useful.  However, the Six Cities agree that if the CAISO believes there is a need for a downward IR product, or that downward IR would provide benefits to the CAISO in the Extended Day Ahead Market, Energy Imbalance Market, or otherwise, it would be useful for the CAISO to include an expanded explanation in the next iteration of its proposal, consistent with the CAISO’s discussion of this issue on March 7/8. 
  • Finally, the Six Cities support consideration and further evaluation by the CAISO and stakeholders of SCE’s proposal to modify IR from a product that is optimized with energy in the integrated forward market (“IFM”) to one that is procured via the residual unit commitment (“RUC”).  While it would be premature for the Cities to take a substantive position in favor of this design at this time, as discussed by SCE, moving IR into the RUC process may mitigate some of the risk of adverse pricing impacts resulting from IR procurement associated with congestion and virtual bidding while potentially enabling elements such as the use of deployment scenarios to assure deliverability under a nodal structure consistent with the CAISO’s preferred approach.  While this approach may represent a seemingly significant pivot in terms of the IR design, SCE suggests that it could provide a simpler path forward that would maintain some of the benefits of the nodal design in the IFM while mitigating some of the risks of cooptimization with energy.  

The Six Cities look forward to continued engagement with the CAISO on these and other issues in this initiative.

Southern California Edison
Submitted 03/30/2023, 04:30 pm


Aditya Chauhan (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

see attached

Tacoma Power
Submitted 03/30/2023, 02:32 pm


Rick Applegate (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

Tacoma Power generally supports the CAISO’s Final Proposal for Day-Ahead Market Enhancements.  While we recognize that the proposal may not be perfect and that future enhancements may be merited, we believe that the proposal significantly improves upon CAISO’s current market offering.

As a potential Extended Day-Ahead Market participant, Tacoma Power sees value in being able to procure an imbalance reserve product from the Integrated Forward Market to help address real-time uncertainty.  We see considerable utility in a downward imbalance reserve product that Tacoma Power could use in the event the day-ahead market has decommitted most or all of Tacoma Power’s flexible generating resources. In these instances, and in the absence of a downward imbalance reserve product, we could struggle to address uncertainty and may fail to pass the downward flexibility test in the real-time resource sufficiency evaluation without taking some form of out-of-market action. 

Tacoma Power would like to thank CAISO’s staff for its work on this stakeholder initiative and for consideration of our comments.


Vistra Corp.
Submitted 03/30/2023, 03:58 pm


Cathleen Colbert (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

Vistra submitted comments on the CAISO’s final Day-Ahead Market Enhancements (DAME) proposal incorporating by reference its comments on the 4th Revised Straw Proposal and stating its opposition to the CAISO proposal due to our concerns it will harm the day-ahead market instead of offer improvements.[1] To strive towards a solution to address needed revisions to day-ahead market, Vistra provided a conceptual framework for a workable imbalance reserve proposal as well as needed changes to drop the downward products and any changes to Residual Unit Commitment (RUC) process in our 4th Revised Straw Proposal comments.[2]

Vistra’s expectation of the DAME delay was that it would allow the CAISO to explore other design proposals that would address a demonstrated grid need or enhance the day-ahead market for a multi-Balancing Authority Area footprint under EDAM. However, CAISO’s focus during the workshops appeared to be to continue work on the designs included in its Final Proposal rather than to collaborate with stakeholders to address concerns stakeholders identified on the CAISO’s Final Proposal.

Vistra expended significant effort during stakeholder discussions to provide useful information for our peers and to provide the requested detailed alternative proposal. Specifically, we provided:

  • Benchmark analysis on how FERC jurisdictional markets across the country are addressing net load uncertainty concerns where we hope the CAISO takes away from this that they are the only market preferring a nodal approach and question what makes CAISO so different;[3]
  • Analysis supporting that there is more than sufficient downward capability such that any downward products likely add no value while introduce added costs and complexity; [4] and
  • Detailed Day-Ahead Market Enhancements design that was developed with EDAM BAAs in mind, to address upward Imbalance Reserve procurement, and respects the existing RUC process through a BAA run using the existing RUC process with minor changes to respect EDAM needs.[5]

The stakeholder discussions held during February 2023 and March 2023 only highlighted that various stakeholders are concerned with adverse impacts of the Final Proposal. During the stakeholder discussions, the CAISO did not put forward new analysis or support for its Final Proposal or otherwise address our concerns that:

  • A nodal approach is superior to a zonal approach,
  • New downward products are unwarranted, and
  • Large-scale changes to its RUC run are unwarranted.

The discussions and efforts that Vistra undertook only further convinced us that our concerns with the CAISO’s Final Proposal are valid. There are still significant challenges that we believe will cause FERC to struggle to approve any filing based on the Final Proposal even if minor tweaks are made. Additionally, the discussions highlighted significant gaps that need to be addressed prior to moving forward with a final design, such as how Western RA program should be considered in day-ahead market operations or how previously contracted resources should be modeled in any BAA-level RUC run to ensure contracts for off-system sales are not counted towards meeting internal needs.

The CAISO’s nodal Flexible Ramping Products initial results presented at the Market Performance and Planning Forum provide analytic support that if a nodal paradigm is implemented it will reduce the efficiency of the day-ahead market.[6] Vistra is concerned the nodal FRP results presented by the CAISO indicate that flexibility is not being secured and compensated appropriately across the Western Energy Imbalance Market, and we will not support an approach that introduces these inefficient results into the day-ahead market solution. The nodal FRP results support that the zonal framework as proposed by Vistra is superior to the nodal framework as implemented by the CAISO.

Additionally, CAISO has indicated it may include storage modeling proposals in a revised final proposal. Vistra is concerned this is premature since the CAISO did not allow time for stakeholder discussions on storage modeling changes. We request the CAISO hold stakeholder discussions and allow for stakeholder feedback on any storage proposals it intends to propose under this effort.

Vistra requests that CAISO extend its timeline further to allow for an alternative zonal proposal for an upward Imbalance Reserve product to be refined through collaboration between stakeholders and CAISO staff, while maintaining the core elements of the proposal for both Integrated Forward Market and Residual Unit Commitment. During this extension, the CAISO could stakeholder storage modeling changes to receive stakeholder feedback and include in a future straw proposal with the new proposal including storage elements. Vistra does not believe small tweaks to the CAISO proposal can address our concerns.

[1] Vistra Corp. Comments on CAISO Day-Ahead Market Enhancements Final Proposal,

[2] Vistra Corp. Comments on Day-Ahead Market Enhancements Fourth Revised Straw Proposal,

[3] Vistra FERC Jurisdictional Markets Flexibility Product Benchmark, Day-Ahead Market Enhancements Workshop, February 27, 2023, slides 17-26,

[4] Vistra FERC Jurisdictional Markets Flexibility Product Benchmark, Day-Ahead Market Enhancements Workshop, February 27, 2023, slides 1-16,

[5] Day-Ahead Market Enhancements Alternative Proposal, Day-Ahead Market Enhancements Workshop, March 7, 2023,

[6] Market Performance and Planning Forum, March 16, 2023, Flexible Ramping Product Enhancements,

Submitted 03/30/2023, 04:52 pm

Submitted on behalf of
Western Power Trading Forum


Kallie Wells (

1. Please provide your organization's feedback on what modifications the ISO should make to its final Day-Ahead Market Enhancements (DAME) proposal based on the discussion from the recent February 27 and March 7-8 DAME workshops:

WPTF appreciates the opportunity to submit these comments on the CAISO’s Day-ahead Market Enhancements workshops held on February 21, March 7, and March 8, 2023. The workshop format generated productive discussions that can be used to start identifying and considering the trade-offs between a nodal and zonal approach for procuring Imbalance Reserves (IR) and between single or bi-directional Imbalance Reserve and Reliability Capacity (RC) products in the Integrated Forward Market (IFM). At this point in the policy development process, there is still significant work to be done and the CAISO and stakeholders need to be committed to following through with the direction provided by the Board to deliver a complete, broadly-supported proposal when seeking approval.

WPTF elaborates on the following five main points in more detail throughout these comments.

  1. The CAISO should not restrict discussions and meaningful consideration of a well thought out zonal approach to meet a self-imposed and arbitrary May BOG and GB meeting deadline.
  2. The current CAISO DAME proposal includes elements that are inconsistent with FERC precedent and failing to address these and other issues during the policy development phase risks a prolonged FERC approval process, which would create more timeline risk than taking the time now to get the policy right. Many of these items are unrelated to the framework discussions.
  3. There are still several outstanding issues that while apparently not directly conflicting with FERC precedent nevertheless need to be addressed in the policy development phase to promote achieving the long-term policy objectives of the initiative.
  4. The market design should entail a framework that is as simple and straightforward as possible while allowing for additional elements to be added as gained experience indicates doing so is justified on a cost-benefit basis.
  5. The CAISO has yet to prove a fully realized nodal procurement design for a capacity product that creates stable, predictable results is implementable from a technology perspective: despite over two years of implementation efforts for the real-time Flexible Ramping Product (FRP) nodal design the full program has yet to be successfully integrated in the market.

Lastly, we have attached a redlined version of the CAISO’s comparison matrix to provide more clarification on certain elements and trade-offs of the different frameworks.

The CAISO should not restrict discussions and meaningful consideration of a well thought out zonal approach to meet a self-imposed and arbitrary May BOG and GB meeting deadline. During workshops the CAISO indicated that they are willing to flesh out a zonal approach for procuring IR for comparison and consideration, but only in so far that they have bandwidth between now and the May BOG meeting. This is an artificial deadline that will include unnecessary compromises made in the zonal design put forth for comparison to the nodal approach. We understand the desire to have DAME implemented along side EDAM but we do not believe that (1) EDAM and DAME need to be filed at FERC together or (2) waiting until June or July BOG will hinder the ability to file and implement DAME alongside EDAM given the Fall 2024 targeted implementation date. The CAISO still has several details of the EDAM design to work out before they are ready to file at FERC. Thus, taking an additional month or two to iterate on a zonal approach and other outstanding initiative items with stakeholders does not risk the targeted implementation date of either policy effort.

The workshops and the subsequent Market Surveillance Committee (MSC) meeting have highlighted the fact that there are still a lot of unknowns and details that need to be worked out for the DAME design regardless the use of a zonal or nodal framework. It is extremely concerning to be at this point in the policy effort where the CAISO is planning to take the design to an upcoming Board meeting but have so many details that still need to be discussed. A main example is the demand curve. Even during the MSC discussion the CAISO was unsure exactly how the demand curve will be structured, what the associated prices will be along the demand curve, the ceiling for the demand curve, and what priority it will have relative to other products in the scheduling and pricing runs. This level of detail has significant implications on the market design performance and overall efficiency and will need to be finalized prior to the tariff filing.

We emphasize that WPTF is not suggesting the CAISO take another six months but rather that the CAISO continue working on the proposal for an additional month or two to design (and review with stakeholders) a workable zonal approach and finalize all outstanding design elements. Stakeholders and the Market Surveillance Committee contributed to the overall effort by providing the CAISO with alternative design options that the CAISO can leverage to produce a new proposal that addresses the concerns raised in this timeframe.

The current CAISO DAME proposal includes elements that are inconsistent with FERC precedent and failing to address these and other issues during the policy development phase risks a prolonged FERC approval process, which would create more timeline risk than taking the time now to get the policy right.  There are several elements of the current DAME proposal that exposes the CAISO to FERC approval risk and therefore are likely to extend the ultimate timeline for policy implementation. These risks, outlined below, exist regardless of moving forward with a nodal or zonal approach, thus they must be addressed prior to FERC filing regardless of the ultimate framework adopted. Additionally, if these items are not addressed, and FERC does not approve the tariff changes, the CAISO could then be in a position of not able to implement DAME alongside EDAM.

  1. Downward IR/RC Product Justification: The CAISO has yet to provide sufficient justification for including the downward products in the DAME effort. In recent FERC filings and Orders, FERC seems to have created a precedent that any new product in an ISO market needs to be justified. In other words, the benefit of the new product (in terms of improving market efficiencies and addressing a need) must outweigh the costs of creating and implementing that product. WPTF is concerned that the CAISO has failed to adequately justify the need for both downward products – IR Down (IR-D) and Reliability Capacity Down (RC-D). WPTF requests that the CAISO provide data that shows the current frequency of running out of economically offered downward dispatch capacity in the day-ahead and real-time markets. This can be done by quantifying (1) hours/intervals when the system marginal energy cost (SMEC) component was -$150/MWh as a result of relaxing power balance constraint, (2) hours/intervals when the market had to cut self-scheduled renewable resources for system or local conditions, and (3) intervals during which a BAA failed the flex ramp down test.[1] The CAISO should also provide a subjective assessment of the impact of (1) expected energy storage awards and (2) increased transfer capability via the EDAM on the likelihood that the market would run short of downward dispatch in the coming years. The CAISO should also assess whether it would be feasible to add IR-D and RC-D in the future should experience post-DAME/EDAM go-live show such products would benefit the market.
  2. Storage treatment: The CAISO’s final proposal removes the market design element that would adjust a storage resource’s State of Charge (SOC) based on assumed impact of providing IR-U/IR-D or RC-U/RC-D (see below for additional concerns regarding storage resources and the RC product). The day-ahead market will thus result in infeasible schedules for storage resources, increasing reliability risk in real-time if they are unable to support day-ahead awards (energy, ancillary service, and/or IR/RC awards). Implementing a market design that will knowingly result in infeasible day-ahead schedules for a large portion of the resource mix poses significant risk both in terms of reliability and FERC approval.
  3. Storage eligibility: The CAISO’s final proposal does note that storage resources are eligible to provide RC-U and RC-D.[2] However, the CAISO is currently working through policy and/or Business Practice Manual (BPM) changes to address the lack of clarity regarding the eligibility for storage resources to receive RUC awards in the existing day-ahead market. Thus, WPTF believes this discussion also needs to be directly addressed in this policy effort. One solution to the current tariff issues regarding the interplay of storage resources and RUC may be to address this policy through creating a framework under the DAME to include storage resources in the RUC process, however, doing so would require significant additional work with stakeholders. WPTF believes that given the size of the storage resource fleet under RA contracts, it would be inefficient and counter-productive to not in some way incorporate such resources into the RUC/RC process.
  4. Reliability risk: As discussed during the stakeholder workshops, implementing a nodal design for IR while maintaining the existing zonal framework for Ancillary Services (AS) will inevitably increase the amount of stranded AS capacity due to the interplay between scheduling resources at the nodal level for IR and the market clearing AS capacity at a zonal level and thereby require increased intervention by system operators to maintain reliability. AS are a reliability product and required per WECC/NERC standards – AS Regulation is dispatched every four seconds by the market to maintain scheduled frequency across the operating day and AS Operating Reserves are dispatched during contingency events to respond to contingency events or other contingency requirements such as Energy Emergency Actions. Thus, ensuring the availability and deliverability of AS should take priority over procuring an IR product meant to manage system or locational uncertainty if it materializes. No market design should compromise the ability for the BAA to access critical AS capacity and energy to ensure BAA can comply with its NERC and WECC reliability requirements. If a zonal framework for AS resulted in system operators having to consistently manage around significant amounts of stranded capacity through manual interventions, then addressing such shortcomings in the market design should take priority over adding an IR product (zonal or otherwise). It is WPTF’s understanding however that  the existing zonal framework for AS has not resulted in significant amounts of stranded AS on a consistent basis and therefore augmenting the granularity of AS procurement has not been identified as a high-priority market design enhancement by the CAISO.  WPTF questions therefore (1) if the CAISO is concerned that zonal procurement of IR is problematic why it is apparently not concerned about the existing zonal procurement of the more critical AS capacity and (2) if the CAISO is satisfied with zonal procurement of AS why it is not also supportive of zonal procurement of IR, at least for the initial DAME policy implementation. WPTF is further concerned that if the CAISO pursues nodal procurement of IR, the disruption such procurement would cause to zonal AS deliverability would necessitate moving AS to nodal procurement concurrently in order to protect critical reliability-focused AS products, which would significantly impact the timing of the DAME initiative.  In short, WPTF does not believe that the CAISO has shown that the expected benefits of nodal IR procurement outweigh the likely costs or are sufficient to support delaying the implantation of DAME to address AS deliverability parity.
  5. Price Formation: The CAISO’s nodal market design will skew rational price formation in the day-ahead market and will produce unjust and unreasonable price signals that are counter-productive to the goal of promoting an efficient and reliable market. The CAISO proposes to set the IR requirement based on the 97.5th and 2.5th percentiles (adjusted for some unknow amount of diversity benefit) of potential uncertainty and assumes 100% of that potential uncertainty materializes in the deployment scenarios. This will result in prices that reflect marginal costs of IR procurement assuming all forecasted potential uncertainty materializes in real-time and prices that reflect the marginal cost of reserving transmission in the event that 95% of forecasted potential uncertainty materializes. These are both unreasonable assumptions. From a statistical perspective, most of the time (e.g., 95% of the time) that level of uncertainty will not materialize and lead to what appears to be congestion pancaking increasing congestion prices inappropriately. While we recognize the in-development demand curve proposal for IR may help mitigate unduly high prices to the extent it results in less than the full requirement being procured when doing so would have a significant impact on the market clearing prices, the details of the various price and MW quantity points along the demand curve have not been thoroughly discussed with stakeholders. Additionally, WPTF is concerned that the price formation will send the signal to deprioritize meeting imbalance reserves when congestion occurs in preference for congestion management, sending inappropriately low prices to a given location where there is need to send the signal to increase flexibility due to congestion impacts that are unlikely to materialize.
  6. CRR shortfall: It is WPTF’s understanding that the CAISO is planning to include a proposal element in the revised draft final proposal that addresses the CRR shortfall concern. We appreciate the CAISO going back to the drawing board on this element and look forward to the details in the next iteration of the proposal. The prior iteration of the proposal was going to move forward with a design that would knowingly increase CRR revenue shortfall, which WPTF strongly opposed. WPTF finds a benefit of the zonal approach relative to nodal approach for IR is there is no CRR shortfall risk introduced under a zonal approach.

There are still several outstanding issues that while apparently not directly conflicting with FERC precedent nevertheless need to be addressed in the policy development phase to promote achieving the long-term policy objectives of the initiative. Throughout the entire policy effort, there are key design elements that for one reason or another were not given adequate, or any, air-time. We are now at the end of the development phase with several still outstanding design elements that must be discussed and finalized before seeking Board and FERC approval. To be clear, WPTF does not see any of the following issues or design elements as implementation details – these are foundational aspects of the market design and thus require resolution prior to seeking approval.

  1. The Demand Curve: The CAISO has failed to discuss in any detail or include in any document the price and MW quantity points (or the formulation for setting those points) that will be used in the demand curve for IR. Furthermore, the level of the prices points in both the scheduling and pricing runs must be discussed prior to seeking Board and FERC approval as the scheduling run prices determine priority order of products/schedules and the pricing run prices are used to set the market prices. For example, the CAISO noted they plan to have the scheduling run demand curve prices set at the same level as the pricing run demand curve prices with the highest point being $1,000/MWh. However, most constraints and requirements in the scheduling run have prices well above $1,000/MWh. Thus, anytime another constraint is binding, the market may not procure any IR because the prices in the scheduling run will be higher than $1,000/MWh price on the demand curve used in the scheduling run. WPTF questions whether operators would be incentivized to reduce the portion of the RUC load biases enforced due to uncertainty concerns, CAISO’s stated objective, if all IR have a lower scheduling priority than energy self-schedules including low-priority exports. This begs the question of why develop a new market product if there is no quantity that the CAISO believes has a firm requirement to be met? It will be challenging to convince FERC there is a need for and benefit to adding an IR product with this priority that cannot achieve the benefit of reducing the load biases.  It is important to keep in mind that there is FERC precedent that requires penalty parameters to be specified in the CAISO Tariff, and as such, the demand curve values may also be required to be included as they will interact with other scheduling priorities and price formation.   
  2. Setting the Uncertainty Requirement: The CAISO is planning on setting the imbalance reserve requirements using the same methodology that is used for the Flexible Ramping Product. Specifically, it is a combination of a MOSAIC quantile regression approach and the original histogram approach. The requirements derived using the histogram approach act as a cap on the requirement. In other words, the requirement will be set to the lower of the requirement using the histogram approach and the MOSAIC quantile regression approach. Based on the data used in the MOSAIC quantile regression approach (interval data and historical averages), you can end up with one interval having a 0 MW requirement and the next interval having a requirement at the cap. The consequence of this approach is that it looks like there is no need in one interval but in the next interval there is a significant need, creating a large swing in the requirement between the two intervals.  In the real-time, this leads to volatile requirements and volatile pricing that may, in reality, not reflect actual need. What is a reasonable requirement has not sufficiently been discussed to gain confidence in the reasonableness of the requirement. Further, it will be critical to publish the day-ahead market’s IR requirements prior to the day-ahead market run on multiple set times similar to how the CAISO publishes its load forecast. For example, it will be increasingly important to publish the IR requirements at a minimum two days prior to operating day and several times in between as we near the close of the day-ahead market window. These inputs will be used in the Resource Sufficiency Evaluation run for EDAM BAAs and will need to be transparent and stable.
  3. Distribution of Uncertainty Requirement: There are three outstanding elements related to the distribution of uncertainty requirement. First, as discussed during the latest set of workshops, the CAISO is proposing to use unreasonable and unrealistic assumptions when distributing the uncertainty requirement in the deployment scenarios’ power flow analysis. Specifically, the distribution methodology distributes uncertainty in a pro-rata fashion using the Load Distribution Factor (LDF) for load nodes to represent assumed increases or decreases in withdrawals and VER forecasts (for wind and solar resources) to represent assumed increases or decreases in resource output. The methodology does not consider variation in load or resource uncertainty based on its location, which may result in inefficient distribution of the uncertainty requirement across the system. It will then cause the market to procure capacity based on this assumed and inaccurate estimate of where uncertainty will materialize with no basis on whether the load or resource location has greater variability. For example, a solar resource located in Central Valley will have less uncertainty than a solar resource located in the Coastal area, where distributing the uncertainty to the Coastal solar at the same rate assumes they are equally likely to experience the same level of uncertainty per MW of forecast. The market may not procure enough capacity in the “right” location that can meet the actual uncertainty that materializes if day-ahead congestion and its impact to the capacity procured is based on these inaccurate estimates. WPTF believes there needs to be additional discussion around the reasonableness of the distribution assumption, especially the appropriateness of distributing to resource locations.

Second, the CAISO is assuming 95% of uncertainty will materialize when distributing the uncertainty in the deployment scenarios. Here again, we know this is an unrealistic assumption that will impact price formation for both energy and the imbalance reserve products.  WPTF believes there needs to be additional discussion around the reasonableness of the assumption.

Third, WPTF would like to better understand how the distribution of uncertainty will be adjusted in the event the demand curve kicks in and does not procure 100% of the requirement. It seems like if the procured capacity is less than the uncertainty distributed in the deployment scenarios, this could result in an infeasible solution. It is our understanding that the CAISO will adjust the uncertainty that is distributed down based on what was actually procured, but we would appreciate additional discussion around that element of the market design. Lastly, because the methodology distributes pro-rata based on LDFs and VER forecasts, it does not take into account the actual uncertainty that may materialize in an area given the physical capabilities of a resource. For example, if a 50 MW wind resource has an energy schedule of 20 MWs, then the most upward uncertainty that should be distributed to that location would be 20 MWs. But there is no constraint in the market that limits the distribution in that manner.

  1. VER Participation: WPTF believes additional discussion needs to be had around participation of VER resources for multiple reasons. First, WPTF does wonder if it makes sense to pay a VER resource for providing upward capacity in the day-ahead market that they will generate in real-time regardless of the award. Wind resources tend to under-schedule in the day-ahead market relative to their forecast but in real-time will generate at whatever level they are able. Does it make sense to award a wind resource a capacity product to reserve capacity above its day-ahead energy schedule in the event it is needed as energy in real-time, knowing it will likely generate at that higher level regardless, assuming it can? Secondly, based on how VERs are generally contracted, they will likely want to bid in a way as to not be awarded IR. This is because they frequently are paid based on what they generate and have contractual minimum levels of generation that must be met rather than operating solely under a standard capacity contract. Thus, they are more likely to bid high for IR because they don’t want to have that capacity reserved in the event the uncertainty materializes. Also, note that MISO recently filed at FERC to make VER resources ineligible to provide its imbalance product. It will be important to understand the underlying issues MISO is facing to evaluate if they are relevant to CAISO’s market design.
  2. Application to non-CAISO EDAM BAAs.  The CAISO has yet to demonstrate how the nodal design will be deployed in the non-CAISO EDAM BAAs or address how differences in congestion management and cost allocation between the CAISO and non-CAISO EDAM BAAs will be dealt with in practice. CAISO has also failed to explain how the CAISO non-EDAM BAAs participating in the Western RA program or have otherwise executed long-term contracts will either reflect these forward arrangements through the market or alternatively how the market design will ensure it does not interfere with the forward agreements’ obligations.

The market design should entail a framework that is as simple and straightforward as possible while allowing for additional elements to be added as gained experience indicates doing so is justified on a cost-benefit basis. On one end of the spectrum is a system framework where one requirement for the entire system is set, which can be met from resources anywhere in the system. On the other end is a nodal framework that forecasts requirements at each and every load aggregation point and VER node, enforces all the constraints in the system to be able to ensure deliverability of acquired capacity, reserves transmission capacity assuming 95% of uncertainty materializes, triggers market power mitigation based on pancaked congestion due to energy and uncertainty, and generates nodal prices for IR while also contributing to congestion costs in the energy LMPs. Given all the unknowns in terms of complexity, accuracy, and magnitude of concerns, WPTF strongly encourages the CAISO to start with a less complex design that can be adapted over time as experience indicates changes are needed. It is much easier to add complexity over time than pull a design back. The CAISO has pursued a nodal approach for the real-time FRP to attempt to address issues that were observed over time in how FRP was being awarded to resources in the fifteen-minute market that were unable to be converted to energy and delivered where needed in the five-minute market. For the reasons discussed during the February and March workshops, while it is conceptually sound to seek a market design for real-time FRP that constrains procurement to the areas most likely to need to convert that capacity to energy in the immediately-following market intervals, that does not mean that the day-ahead IR will experience the same issues as the real-time FRP or has the same level of criticality as the real-time FRP and therefore it is questionable whether the day-ahead IR product  warrants a similar design. Furthermore, as discussed in more detail in the subsequent section, the recent experience with nodal FRP does not indicate that a nodal framework for a capacity product can be successfully implemented. There are various ways in which a framework could be constructed on day one that allows for added complexity over time. We believe this should be a point of discussion during the next stakeholder meeting on DAME.

The CAISO has yet to prove a fully realized nodal procurement design for a capacity product that creates stable, predictable results is implementable from a technology perspective: despite over two years of implementation efforts for the real-time Flexible Ramping Product (FRP) nodal design the full program has yet to be successfully integrated in the market. On February 1, 2023, the CAISO finally deployed nodal procurement for FRP. Throughout the DAME discussions, the CAISO continually pointed to FRP nodal procurement as the design and implementation structure they are using as a foundation for the nodal procurement of imbalance reserves. Originally nodal FRP was going to be implemented on a timeline such that the CAISO and stakeholders would have had ample time to understand, and get comfortable with, the nodal FRP design prior to finalizing the DAME nodal imbalance reserve design.  While we recognize there is only one month of market data from which we can evaluate the performance of nodal FRP, even in this short amount of time, there are some obvious concerns with the performance to date that render nodal implementation of imbalance reserves extremely questionable. 

WPTF has listed below the significant issues with nodal FRP implementation that warrant the CAISO and stakeholders to seriously reconsider if nodal procurement of IR is appropriate, especially on day one. It is imperative that we keep in mind that even a small inefficiency in the day-ahead market will be magnified in terms of its impact given the increased volume of energy transacted and products procured in the day-ahead time frame relative to the real-time market. This magnitude will become amplified under an Extended Day-Ahead Market.

  1. Due to implementation complexities, the CAISO has had to drastically cut back on the types and quantities of transmission constraints enforced in the nodal procurement of FRP. It is our understanding that the CAISO is not enforcing nomograms or contingency constraints. Based on that, what was actually implemented looks more like a zonal framework with one large area made up of several BAAs that pass the Flex Test with transfers limited between BAAs within that area, and in some cases a few smaller zones (for the BAAs that fail the Flex Test), but with nodal pricing. While there are internal base case flow constraints enforced within the BAAs (i.e., internal non-contingency transmission constraints), given the minimal amount that actually bind (see point #2 below), they do not seem to be providing commensurate benefits but rather simply generate non-sensical price signals (see point #4 and #5 below).
  2. The number of constraints binding in the CAISO WEIM BAA and non-CAISO WEIM BAAs call into question the need for a complex nodal design. The CAISO presented data during the March 16 Market Performance and Planning Forum (MPPF) that showed the number of unique binding constraints by BAA and month.  The CAISO WEIM BAA had the most, but the month with the highest number of constraints binding was still only 183 unique constraints that were binding (occurred in September 2022). To clarify, that is not to say that in one interval there were 183 constraints binding, but rather across the entire month there were 183 unique constraints that were binding in at least one interval – not simultaneously binding. This represents a small fraction of all constraints. For the non-CAISO EIM BAAs, it was drastically lower with the highest of all BAAs being only 7 unique constraints binding in a month (LADWP in October 2022). Given the minimal number of constraints that tend to bind in all the BAAs across all months, WPTF questions if stranded capacity is a concern that warrants the overly complex market design for imbalance reserves.  
  3. A shift in procurement patterns of flexible capacity may reduce, rather than increase, operator confidence. With nodal FRP procurement, there has been a drastic shift in where the capacity is being procured. The capacity procurement is now more concentrated in some BAAs rather than being spread across several BAAs. The most significant change is the stark decrease in flexible capacity being procured from within the CAISO WEIM BAA. This is likely because when nodal FRP was implemented the CAISO simultaneously removed the minimum Flex Ramp Up/Down requirements that were in place for the CAISO BAA. It is important to recall that the reason the minimum requirement was implemented in the first place was that operators were concerned that the flexible capacity was predominately being procured in other BAAs and were not confident they would be able to rely on that capacity if transmission deliverability concerns arose. Now it appears with nodal implementation, we are back to that timeframe of October 2020 and re-introducing this operational concern that may lead to further operator intervention rather than decrease operator intervention.
  4. The nodal prices, while mathematically correct, are meaningless from an economic perspective based on WPTF’s understanding of the intent of the IR product.  When there is a non-zero opportunity cost for providing flexible ramp up or down, and the market produces non-zero prices, most of the nodal prices across the system are negative[3].  Negative prices indicate that the system has more – actually, too much - flexible capacity than it needs. Which, if that is the case, then we should be asking ourselves why do we have a separate product for flexible capacity? The only nodal prices that are positive tend to be at nodes where the capacity provides “counterflow” on a constraint that is binding in the deployment scenario. This sends the signal that flexible capacity is only valued from resources that can provide counterflow on a transmission constraint, and valued more from those resources than ones that flow across non-binding constraints (i.e., not stranded behind any constraint). The nodal pricing in these situations seem to price the flexible capacity more for its ability as congestion management in the current interval rather than capacity to meet ramping needs in the upcoming interval. This mathematically makes sense if the purpose of the product is to provide additional capacity to help manage day-ahead congestion. However, this is not WPTF’s understanding of a rational design for a new Imbalance Reserve product with the goal to ensure capacity to meet flexibility, which should not be valued lower than congestion management.
  5. Nodal FRP has not resulted in stronger price signals, which was one of the main justifications from a price formation perspective. The nodal prices of FRU/FRD continue to remain predominantly $0/MWh even though one of the main objectives of nodal FRP from a price formation perspective was stronger price signals. When the FRU/FRD requirement is being met from resources that all have a $0/MWh opportunity cost, then the nodal prices across the system are all zero. This seems to occur frequently even though one of the main justifications for nodal FRP from a price formation perspective was that it would provide stronger price signals. It could be that there are ample resources with $0/MWh opportunity cost because the CAISO was unable to implement the design with all constraints enforced and simultaneously removed the minimum requirement for the CAISO BAA and allowed for pooled BAAs. This will require additional discussions to understand whether the results will change in near future as constraints are added or not.
  6. The added granularity of nodal prices do not provide any additional rational transparency into the valuation of flexible capacity. As discussed earlier in these comments, the “SMEC” like component of the nodal FRP prices is negative when there is a non-zero opportunity cost of providing the product. A negative marginal cost of providing the capacity product does not make economic sense. Additionally, it is our understanding based on the discussion during the MPPF call that the reason its negative is because the SMEC and congestion components are having to interact in a way to ensure the resulting nodal price at locations where resources are being awarded reflects the opportunity cost of the marginal resource providing the product. In other words, it seems as though the underlying nodal pricing components are being set in a way that diverges from the meaning of each of those components but rather are used to ensure the combination of the two (SMEC and Congestion component) equals the opportunity cost of providing the product.  Put differently, there is not only an opportunity cost of that capacity relative to being used to meet energy but also an opportunity cost relative to being used to manage congestion. Lastly, the CAISO is not further distinguishing between congestion that is due to base case, upward, or downward deployment scenarios in the energy prices. Thus, an energy LMP may have a $0/MWh congestion component but in reality there were two non-zero but offsetting congestion components from two of the three scenarios.
  7. Nodal FRP has not increased operator confidence such that they have reduced HASP biasing. Reducing HASP biasing was one of the main objectives of nodal FRP – similar to how reducing RUC biasing is a main objective of DAME. However, based on OASIS data shown in the first chart below, implementing nodal FRP does not appear to have reduced HASP biasing. If anything, there may be an increase in HASP biasing following nodal FRP implementation. WPTF does recognize that the increase may be attributable to seasonal trends and January – March 2022 data is not available to isolate that effect. However, when comparing the week prior to nodal FRP implementation to the week immediately after nodal FRP implementation, there is still an increase in HASP biasing. It could be the case that even with nodal FRP, operators are still not confident in where the flexible capacity is being procured and thus continue to bias HASP.

Figure 1: Average Hourly HASP Biasing by Month January 1, 2023 – March 23, 2023[4]


Figure 2: Average Hourly HASP Biasing Jan 25, 2023 – Feb 7, 2023[5]

  1. WPTF is concerned that the CAISO has implemented changes that were not properly stakeholdered. First, the CAISO noted it removed the flexible ramp up and down minimum requirement applied to the CAISO BAA. This was put in place to provide operators more confidence in where the capacity was being procured to meet ramping needs within the CAISO BAA. It was needed because the requirement reductions (diversity benefit credits) counting on imports and exports were beyond levels that a balancing authority area could feasibly support. [6] At the time the minimum was introduced, the CAISO was the largest driver of the system-wide flexible ramping product requirement because it has the largest share of load and variable energy resources across WEIM. However, because CAISO BAA has large import and export capability its requirement was effectively made zero by including the diversity credit. Since the CAISO was a large driver of the flexibility need across WEIM, it was not, and likely is not, appropriate to transfer the obligation to meet flexibility completely outside the BAA both on a fairness basis and on a reliability basis where if the transfer capability was impacted the BAA may not be able to reliably serve load.  We are unclear at what point in time the CAISO stakeholdered the removal of that requirement, which required FERC approval to be implemented in the first place, or at what point they provided data to show a change to the trend of CAISO being the primary driver of the flexibility need such that the fairness or reliability concerns are moot. Second, the CAISO explained that with the nodal procurement of FRP, the group of BAAs that pass the Flex Test will be pooled together when procuring the capacity. WPTF acknowledges that the pooled approach is being discussed in the EDAM market design process for the WEIM RSE, but we are unclear when the CAISO stakeholdered this change for the procurement of flexible ramping capacity in real-time.

WPTF has provided redlines to the CAISO’s attached matrix and asks that the CAISO accept or provide a response if they disagree with the redlines.  Note that WPTF added a column to identify the trade-offs between each framework. In some cases where the CAISO originally included trade-off discussions under the corresponding framework column, that discussion has been moved to the trade-off column in the attached redlined version. WPTF appreciates the matrix and believes it represents a good first step in evaluating the two frameworks. We ask that it be updated and discussed in an additional workshop after the CAISO has considered stakeholder comments.


[1] WPTF is seeking CAISO analysis on the topic. Vistra provided its analysis during the February 27, 2023 workshop on downward products analyzing the first (slides 12-16) and third (slides 9-10) data point. It would be preferrable for CAISO to also provide downward need analysis.

[2] See Appendix A: Eligibility Table

[3] The minimum requirement constraint for the flexible ramp up and down products, when binding, has resulted in a negative shadow price and negative “SMEC” like component for the product. Thus, for all nodes where there is no offsetting congestion from the few transmission constraints enforced in the deployment scenarios, the prices remain negative.

[4] This data is based on the HASP load adjustment data posted on OASIS.

[5] This data is based on the HASP load adjustment data posted on OASIS.

[6] Flexible Ramping Products Refinements, August 31, 2020, Page 6,