Comments on Draft final proposal

Extended day-ahead market

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Comment period
Nov 03, 04:00 pm - Nov 22, 05:00 pm
Submitting organizations
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ACP-California
Submitted 11/22/2022, 03:45 pm

Submitted on behalf of
ACP-California

Contact

Caitlin Liotiris (ccollins@energystrat.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

ACP-California continues to broadly support the expansion of organized wholesale markets, with the hope that EDAM may, ultimately, help take the next step towards a Western RTO. As long as they are well designed, market development efforts in the West, such as EDAM, will provide meaningful benefits to a diverse set of existing and future clean energy resources across the footprint. We are hopeful that the ultimate EDAM design will provide these benefits. And we appreciate the work of the CAISO team to help improve EDAM’s design throughout this process.

ACP-California greatly appreciates several modifications that were made to the Draft Final Proposal to help improve the treatment of transmission in the market and balance the optimization with the Open Access Transmission Tariff (OATT) framework that will continue to exist outside of CAISO. We also appreciate the willingness of CAISO to work with stakeholders to find a workable solution to the transmission requirement within EDAM BAAs that was added to the Draft Final Proposal. As CAISO is aware, the proposed requirements as written in the Draft Final Proposal were highly problematic. The updated proposal, presented at the November 14th stakeholder meeting, is moving in the right direction but additional adjustments are necessary to ensure that the proposal allows generators to participate in EDAM with known costs and to ensure cost recovery is appropriately accounted for. We look forward to working with CAISO and other stakeholders to finalize the design ahead of Board and Governing Body consideration.

In general, these comments focus on elements of the Draft Final Proposal that differ from the Revised Straw Proposal. But we also wish to reiterate points made in prior comments that have not yet been addressed or broadly discussed.

First, ACP-California reiterates the importance of maintaining a mechanism within EDAM for demonstration of delivery of resources to loads. This functionality is especially important for renewable resources located outside of California that deliver to California LSEs under Portfolio Content Category (PCC) #1 of the California RPS, as they will still need to demonstrate their delivery to CAISO in an EDAM paradigm. The Draft Final Proposal does not add any further detail beyond that which was previously stated in the Revised Straw Proposal. Therefore, the questions ACP-California outlined previously on this topic persist and we hope will be addressed in future EDAM discussions. 

Second, we continue to urge the CAISO and EDAM Entities to work toward a standardized EDAM Entity Tariff. Many critical components of the market design will be included in the EDAM Entity OATTs. The more standardized these OATTs can be, and the earlier stakeholders can review them, the better affected parties can understand the overall impact of EDAM. We also continue to believe that there may be an appropriate oversight role for the EIM Governing Body in reviewing the tariffs to ensure consistency with the overall EDAM framework.

ACP-California appreciates CAISO’s efforts to develop the EDAM market design. While some concerns persist and work remains, we appreciate all CAISO has done to help improve the market design over the course of the stakeholder process. We look forward to continuing to engage with CAISO as the EDAM design moves to approval and into the next phase of development. 

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

Under the “EDAM Participation Model” section of the EDAM Draft Final Proposal, a new proposed transmission requirement for generators in EDAM BAAs was added. The proposed requirement was for generators in an EDAM BAA to have one of three types of transmission service as a condition of participation in the market. While ACP-California recognizes and greatly appreciates CAISO’s proactive efforts to make modifications to the proposal that was written into the Draft Final Proposal, we submit the following comments to give further perspective on this topic and highlight that additional modifications are necessary, even from the updated requirement presented during the November 14th EDAM meeting.

ACP-California understands the reasons that CAISO added this transmission requirement and the concerns it is seeking to address, which are – at their heart – about transmission cost shifts and potential revenue attrition for transmission providers in EDAM. While we, generally, do not support a transmission requirement in EDAM BAAs, we are willing to accept such a requirement as part of a compromise to successfully implement EDAM, so long as the ultimate requirement is reasonable and is known ahead of time such that generators can incorporate appropriate costs within their bids into the market. We also support having this requirement standardized across the EDAM footprint and, thus, included as part of the CAISO market design and tariff, rather that leaving it to individual EDAM Entities to implement, which could lead to differing requirements across the footprint.

As CAISO is aware, the proposed design as written in the Draft Final Proposal was overly restrictive and unworkable. It required that suppliers in OATT regions would need to have one of the following types of transmission service: (1) be a designated network resource under the OATT, (2) reserve point-to-point transmission service (to the EDAM Entity border in at least a monthly duration), or (3) hold a pre-OATT legacy contract. These requirements, particularly around holding firm transmission rights, would be highly problematic for some generators and could even strand some existing resources, leaving them unable to bid into EDAM or transact bilaterally (since EDAM participation is not voluntary for resources in an EDAM BAA and there is no mechanism to “opt-out” of the market). We will not reiterate the reasons this requirement was so problematic, as CAISO has heard these concerns from multiple stakeholders and, as a result, presented a revised proposal during the November 14th stakeholder meeting.

The adjusted design for a transmission requirement, presented during the November 14th meeting, where resources that do not meet the transmission requirements from the Draft Final Proposal can bid into the market subject to a transmission charge based on a daily point-to-point rate, is a significant step forward from what was included in the Draft Final Proposal. But additional work is still required, and modifications are necessary, as outlined below:

  1. Transmission rate should be hourly in nature and known ahead of time: While it may be lower (when spread across many hours), the use of a daily transmission rate for this requirement is problematic. Generators cannot easily incorporate the daily transmission cost into their hourly bids with any certainty. Therefore, they may have to increase their bids to address the uncertainty as to how many hours they might be dispatched by the market and be able to spread out recovery of this charge over. Or, alternatively, CAISO may need to establish some sort of bid cost recovery mechanism to ensure generators can recover this daily charge when dispatched into EDAM in an insufficient number of hours to recover these costs. To address these issues, ACP-California urges the CAISO to find a rate which is hourly in nature and is known ahead of time such that it can easily be incorporated into bids.
  2. There needs to be further consideration of the implications of this charge for the EIM. If this type of transmission requirement, and associated charge, is incorporated into EDAM’s design, additional discussions need to occur on the impact to the EIM. Currently, in the EIM, no such transmission requirement or charge exists. In the EIM, generators that are dispatched above their transmission rights are not charged any incremental fees. This proposal would implement different treatment for EDAM, and we believe additional discussions are necessary to ensure that there are not unintended consequences and problematic incentives created.
  3. Further consideration is needed on the impacts to the Transmission Revenue Requirement cost recovery under Bucket 3 as a result of this new charge. This new transmission charge would address transmission cost shift issues and help to keep transmission providers “whole” for short-term transmission sales that would have otherwise occurred to generators that do not have a legacy agreement, firm transmission rights, or are not a designated network resource. This problem is also being addressed through the “Bucket 3” transmission revenue recovery mechanism. Thus, if this new requirement is added to generators, the amount collected through the EDAM transmission revenue recovery mechanism may need to be adjusted downwards when these types of charges are collected from generators. We also suggest that there may be an uplift allocation approach for Bucket 3 costs that could be used to address this issue. For instance, Bucket 3 uplifts could be allocated to load and to generators that do not otherwise have transmission service. As long as the uplift cost was known in advance, generators without transmission service could include those uplift costs in the appropriate EDAM bids.
  4. Details on the other transmission service requirements that would prevent this charge should be clarified. For instance, any type of firm transmission service in an EDAM BAA should prevent a generator from being charged this fee/uplift. The transmission service should not need to be monthly in duration, any specific firmness, nor should it need to be to any specific point in the EDAM BAA (such as to the EDAM BAA border). These details should be clarified in the Final Proposal.

ACP-California is willing to work with CAISO and the EDAM BAAs to find an acceptable solution to this concern, such that generation in EDAM will continue to pay for transmission service. As outlined above, we strongly believe further discussions on the details of the exact transmission requirement are necessary to avoid any significant negative impacts to generators and the market overall. We look forward to working with the CAISO team to address these outstanding issues and develop a workable solution.   

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

N/A

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Since ACP-California has addressed the problematic new transmission requirement for resource participation in question 2, we will focus the following comments on the other aspects of the transmission availability proposal. The transmission commitment framework for EDAM has come a long way from the Straw Proposal, and ACP-California strongly supports maximizing the amount of hurdle-free transmission made available to the market for optimization. While we still have some concerns regarding the bucket framework and its implementation, we appreciate a number of improvements that were made in the Draft Final Proposal.

First, we appreciate that CAISO has better aligned the timing of transmission release for Bucket 2 (now 9am) and Bucket 1 (10am) transmission. However, ACP-California still has concerns with respect to the differing timelines between these two buckets. As CAISO has acknowledged, the buckets largely merge from an operational standpoint and are most useful in distinguishing between who is making the transmission available, the type of transmission being made available, and the disposition of transfer revenues that may accrue. It would be most equitable for the deadlines for releasing this transmission to be entirely consistent and we urge CAISO to further consider if that would be workable in the Final Proposal.

ACP-California greatly appreciates the CAISO’s efforts to address concerns about Bucket 3 and the utilization of transmission rights between the day-ahead and real-time. Specifically, we want to thank CAISO for including a new element in the Draft Final Proposal which would have EDAM transmission providers hold all firm point-to-point and NITS customers harmless from the EDAM transfer and congestion costs incurred in scheduling on transmission rights between the EDAM scheduling deadline and real-time. This would be done “to the extent feasible” by offsetting costs with EDAM transfer and congestion revenues, with shortfalls or excesses of these offsets allocated to measured demand. ACP-California views this as a significant improvement, signaling that the value of holding transmission rights (including long-term rights) in EDAM will not be substantially diminished and this element will help reduce the likelihood of cost-shifts which the market design is not structured to recover. However, it is also important to recognize the degree of autonomy that currently appears to be provided to the EDAM entities under the market design. Since this proposal may largely be operationalized in the precise language of the OATTs, along with business practices and implementation, ACP-California has questions on how this design will be achieved in practice. We believe additional discussions will be necessary with CAISO, EDAM Entities and stakeholders to ensure this proposal is appropriately implemented.

While the EDAM transmission “bucket” design is imperfect, we appreciate how far it has come and CAISO’s effort to address concerns that have been raised during the course of the stakeholder process. We are hopeful that the current design has struck the right balance and will help facilitate an efficient market optimization, while preserving the general OATT framework.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

ACP-California supports the structure for TRR revenue requirement included in the Draft Final Proposal, particularly the proposal to collect TRR shortfall from load only. As ACP-California expressed in our comments on the Revised Straw Proposal, we believe this allocation methodology is more straightforward and efficient than an allocation to load and supply. But we recognize, as discussed more in our response to question #2, that it may be most efficient/appropriate to allocate some of these costs to certain generators dispatched into the market that do not meet the other transmission requirements.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

N/A

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

N/A

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

N/A

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

N/A

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

N/A

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

N/A

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

N/A

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

N/A

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

N/A

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

By creating a framework where external resource participation is largely enabled, CAISO would increase market efficiency as resources outside the footprint are allowed to make offers and be optimized by the market dispatch. Despite these benefits, it is clear that generic external resource participation raises a number of questions and design challenges that are difficult to address. In the previous iterations of the proposal, CAISO has taken steps to enable participation from these resources and has extended parts of that framework in the Draft Final Proposal.

While we are supportive of these changes and the overall expansion of the framework conceptually, we believe that CAISO needs to make modifications to the proposal to ensure that entities that own transmission rights can wheel-through the EDAM footprint. As currently written, the Draft Final Proposal would not allow any non-dynamic, non-contracted external resources to either self-schedule or economically bid at the CAISO interties. However, some form of scheduling will be necessary in order for those with transmission rights across EDAM to wheel-through the footprint. Given that it is unlikely that EDAM will be a highly contiguous footprint at its start, the feasibility of wheel throughs is a significant one. Under the terms currently included in the Draft Final Proposal, there would be no way for an entity owning transmission rights across EDAM to wheel-through it and deliver to an entity that is not part of EDAM. We strongly suggest additional discussions on this element and urge CAISO to ensure the ability to wheel-throughs for non-dynamic, non-contracted supply that have transmission rights across the footprint.

Finally, while not precisely related to external resource participation, ACP-California requests further consideration and detail on how resources will demonstrate delivery to CAISO for RPS compliance purposes. In our previous comments on the Straw Proposal and Revised Straw Proposal, we have requested clarification that dynamically transferred resources from within would be able to continue delivering as they do today (with associated e-tags to demonstrate delivery to CAISO) and how non-dynamic resources could demonstrate delivery to CAISO in order to meet the specific requirements of the California RPS. Little additional details have been provided in the Draft Final Proposal, and outside of self-scheduling there appears to be no other option for resources to deliver from within or across EDAM to CAISO. As such, ACP-California is concerned that there has not been sufficient consideration for how the RPS delivery requirements will interact with EDAM. And we hope these discussions will take place as part of the next phase of EDAM development.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

N/A

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

N/A

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

N/A

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

N/A

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

As a principle, ACP-California supports direct settlement options for transfer revenue and congestion rent allocation. The autonomy that BAAs/Transmission Providers have in their approaches to suballocation to customers creates significant uncertainty for how generators and loads within the BAA will be impacted by EDAM. Therefore, it is essential for BAAs/Transmission Providers to either develop a standard approach to suballocation or for CAISO to expand the options for direct allocation so there is improved consistency across the EDAM footprint.

While there have been improvements in the ability for non-BAA/TSP transmission customers to directly be allocated transfer revenue from CAISO, expansion of this optionality is not only appropriate but essential for these customers. To that end, we support implementing direct transfer and congestion revenue allocation for Bucket 2 Pathway 2.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

Like our comments on Transfer Revenue and Congestion Rent Allocation, ACP-California supports standardization and consistency in settlements and suballocations to load and generation customers within EDAM BAAs. To the extent possible, there should be more direct settlement relationships between CAISO and third-party load, generators, and transmission customers. In cases where direct settlement relationships are not prudent, ACP-California strongly supports a standardized plan or template for suballocations to facilitate transparency and equal treatment for loads and generators that transact across multiple EDAM BAAs.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

N/A

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

N/A

Arizona Public Service
Submitted 11/28/2022, 12:49 pm

Contact

Tyler Moore (Tyler.Moore@aps.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

APS appreciates the opportunity to comment on the EDAM Draft Final Proposal and the extensive work put into the proposal by CAISO and informed by stakeholders. We provide detailed areas of support, dissent, and need for clarification in the forthcoming responses to the CAISO’s numbered questions. However, we want to clearly outline several previously communicated areas of importance to APS upfront.

  1. Governance –The current structure is not sufficient for APS to commit to EDAM and may be an impediment to addressing market design issues in the short and long term.  To have an equitable organized Day Ahead market, governance must be free of undue influence by one state. APS recognizes the passing of ACR 188 and looks forward to the report on regionalization benefits that could be unlocked if the governance structure is modified.  
  2. Resource Adequacy – APS believes that a common RA structure for all participating entities (including CA/CAISO) is needed to have a well-functioning DA market. The current design presumes different RA requirements will apply to different participants, including different definitions of what “counts” as an RA resource. A daily RSE requirement does not resolve this problem, because as we have seen in the WEIM entities can pass the RSE while being deficient and in Energy Emergencies.
  3. Transmission Wheel Through – APS requires resolution on this existing issue that respects the forward procurement of resources and transmission done by non-CA entities in a fair and equitable manner to that of CA entities utilizing the CAISO transmission system. APS would like to see transmission service procured in the proposal TSMSP Phase 2 proposal being commensurate with firm point to point OATT service priority.
  4. Price formation – APS acknowledges that a separate track is ongoing on this subject but is appreciative of the recent movement in this track and phasing of the discussion areas as market participants weigh any changes that could impact their participation within EDAM. APS believes this is an essential aspect of the market design. 
2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

APS generally supports the voluntary participation framework proposed and appreciates the incorporation of transitionary measures included in the revised straw proposal. APS would like to better understand the transitionary measure of market disruption of an EDAM participant initiated by CAISO, and if an EDAM entity could initiate a market disengagement. This is something that has been developed in WEIM that has served entities well to coordinate disengaging from the market during events like IT outages or other planned events that impact WEIM entity’s ability to communicate to market applications or transmit data for market functions. These planned events being well coordinated to other impacted entities has shown to be a best practice to limit impacts to the market and other participants.

 

Metering requirements of new participating resources (NV), mandatory participation of LSE’s and metering to sub-divide their load and resource along with the associated aspects of the resource sufficiency evaluation.

 

Supply offers needing a reservation to the EDAM border, could it just be financial so not to tie up ATC. Wheeling reservation through APS to another EDAM entity from an EDAM entity, the intermediary TP should still receive compensation to not erode revenues from the reservation of the long-term transmission they hold today.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

APS supports the constraint with the additional elements presented in the stakeholder meeting around also limiting the amount of imbalance reserves and reliability reserves to the constraint to avoid awards of capacity to address uncertainty resulting in a deficiency to an entity in real-time as presented in the example scenario within the proposal.

 

 APS believes that leaving operator discretion to make decisions in haste is problematic and is interested in specific protocols and tools to help differentiate the various priorities and operator expectations to facilitate the priorities in real-time. 

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

APS is concerned about the EDAM market utilization of unscheduled transmission in bucket 2 pathway 2 and if there is any reprieve from the market from using more transmission capacity than the transmission provider has if the original reservation holder schedules the transmission in real-time causing unreserved use or overruns. In addition, if these were to occur what information would be available to transmission providers to accurately allocate to the transmission customer any necessary charges.  

 

APS also does not see an apparent relative prioritization of transmission usage if the EDAM market has transmission available to it from different buckets. Would EDAM utilize all bucket 1, then bucket 2 (pathways in order), and finally bucket 3 transmission if it were to use a partial amount of the total transmission made available for transfers. APS believes that identification of what transmission availability was utilized to schedule EDAM transfers will be important so appropriate allocations can be made.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

No further comments.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

No further comments.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

No further comments.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

 APS believes that the EDAM entity should not be required to show transmission demonstration as part of the ancillary services obligations that each entity retains as a balancing authority area. It is unclear what the market operator would do with this information, as an EDAM entity can adjust the transmission made available to the market for any necessary reserve sharing program deployments that may be represented by TRM, CBM, or otherwise utilized by the balancing authority area to maintain compliance with their obligations to reserve sharing groups.  

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

No further comments. 

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

 APS does not oppose the ability for entities to hold back supply above the RSE and supports the net EDAM transfer export limit with additional design elements proposed in the workshop to manage a sufficient BAA being exported to a deficient position through energy and capacity products. 

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

No further comments. 

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No further comments. 

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

APS appreciates the price formation enhancement and is engaged in that forum as it pertains to market power mitigation within EDAM. APS believes that a significant consideration and potential adoption of conduct and impact tests for market power mitigation. APS requests that CAISO continue to make progress in the initiative by way of a straw proposal being created.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

APS would support the evaluation of convergence bidding activation in EDAM entity areas after EDAM launch but does not oppose a planned transition at this point understanding that stakeholders can provide input to the transition plan after operational experience is achieved in the EDAM, including any modifications to convergence bidding that would be justified for convergence bidding across the EDAM footprint. APS does not oppose the transition period, or election to allow convergence bidding at the onset for BAAs proposed by CAISO and believes that any market design flaws that could be problematic and exploited by convergence bidding should be addressed expeditiously by the CAISO in the early onset of EDAM.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

APS supports the proposal of external resource participation to be done through dynamic schedules and pseudo-ties like is done in WEIM today. APS has performed a considerable amount of work to implement pseudo ties for resources located outside of the BAA under this framework.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

APS seeks clarity in the Draft Final Proposal on Page 99 in the sentence “The ISO limits GHG attributions to the lower of (a) the GHG bid capacity, (b) the resource’s optimal dispatch, and (c) the positive difference between the highest energy bid capacity and the resource’s base schedule.”, is part B referring to the IFM schedule? It is not clear but we believe that is the IFM schedule and if so it could be clarified since the subsequent language begins to discuss optimal schedules in the reference pass.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

APS is concerned surrounding the ability to deem generation that is not incremental to reference level pass amounts to serving CAISO load in the resource-specific approach. Deeming of energy from resources that do not increase output above the reference level pass, or worse decrements energy output can impact the accuracy of marginal congestion cost and erode the environmental benefits intended by the GHG program. APS would seek to continuation and work with CAISO are evaluation of the proposed constraints and future improvements to accuracy and reporting.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

APS believes that net export capability should not be used, and CAISO should use net export transfers relative the GHG reference pass. The utilization of export capability to calculate ability to deem GHG obligations to an EDAM BAA appears to be inaccurate since capability does not equate to transfers above the reference level pass. APS believes that capability is utilized to ensure that GHG bids are available for deeming, but this could be down by other methods like the utilization of unspecified rate as one stakeholder commented if the CAISO were to exhaust all resource specific GHG bids.

 

APS is in agreement with the exceptions for RA capacity from the constraint as counting this supply against the constraint would inaccurately account for energy procured by CAISO LSE’s to serve as RA as having to meet the export constraint of an EDAM BAA.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No further comments 

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

No further comments 

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

  APS would appreciate further clarification and examples on the following settlement topics:

  1. Allocation methodologies for CAISO BAA vs other EDAM Entities – it appears there are different methodologies for BCR allocation and Neutrality offsets for EDAM entities vs. the CAISO BAA. APS would like to see a comparison of the allocation methods in each of the settlement categories to understand if there is a benefit of one over the other and any other financial/cost shifting impacts
  2. IRU/IRD and FRP Settlement in Real Time – APS requests enhanced training and further clarification on how IRU/IRD awards may impact FRP settlement in RT for EDAM entities as well as EIM only entities.
  3. Real Time Offsets – APS requests an example for the modified RTIEO calculation demonstrating how removing the financial transfer value and developing the GHG offset will impact the overall calculation in Real Time as discussed in section II.D.2.dd of the draft final proposal.
22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

APS believes the framework for EDAM fees based on implementation and administrative fees in the WEIM is a reasonable approach.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

An important element to the success of EDAM and the larger Western Interconnect is the ability to participate in WRAP and not interfere with the ability of WRAP participants to benefit from the WRAP program. APS sees this coordination among WPP, SPP, and CAISO as an aspect where all three entities need to address the program in a fair and equitable manner. The CAISO should assume that there is a need to address WRAP participants that are within EDAM, withing Markets +, and outside of both EDAM and Markets +. There are various elements that need to be considered in this coordination including energy schedule priorities, timelines, RSE requirements, WRAP holdback requirements, and likely others.

Avangrid Renewables
Submitted 11/22/2022, 02:28 pm

Contact

Molly Croll (molly.croll@avangrid.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

As stated in our comments on the first straw proposal, Avangrid Renewables supports the development of western regional markets toward the development of a fully formed western RTO, which would eliminate pancaked transmission tariffs, optimize dispatch of generation across a large footprint within the WECC, and promote reliability through resource diversity. We are hopeful that EDAM will be a successful interim step to integrating the CAISO and surrounding western BAAs.

The CAISO has introduced some beneficial changes in the draft final proposal. In particular, we support the improved options for transmission customers as part of the EDAM transmission utilization model. We also support the CAISO’s efforts to make accommodations in the design to support WSPP-C contracts and thereby avoid disruption to certain market norms.

We remain concerned about the potential of EDAM to degrade the value of long-term transmission rights held by transmission customers of OATT entities. As the CAISO moves into EDAM implementation, we request that the CAISO maintain attention to this issue and enable future reforms in the market design to address identified inequities or unintended outcomes.

Similarly, we expect that designing a program for GHG accounting that suits the requirements of the California Air Resources Board (CARB), Washington Department of Ecology, and generators and LSE/LREs both inside and outside GHG areas will need to be an iterative process. The CAISO should remain open to reforming its design as participants and regulators come to understand the practical and economic impacts of the proposed GHG accounting framework. We recommend the CAISO hold a workshop with CARB in early 2023 to explain and identify the options and obligations for generators participating in EDAM and potentially delivering energy to California.

Finally, we recognize that the EDAM design process has focused on the needs and benefits of transmission owners and BAAs who may become EDAM entities. However, we reiterate the request made by various stakeholders including ourselves to host a workshop focused on the options and obligations of third-party generators who will be brought into or potentially excluded from the market based primarily on the decisions of BAAs. EDAM should facilitate robust competition and participation by independent power producers to maximize the benefits of the market. Up to this point, this stakeholder group has been a secondary focus in the design process and many questions remain about our roles, risks, and opportunities.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

Avangrid Renewables has several comments on this topic.

First, we support the voluntary participation model for BAAs but we note that the formation of EDAM will have significant impacts on EIM-only entities, just as the formation of EIM has significantly affected bilateral market outside, but surrounded by WEIM. Avangrid Renewables operates a generation-only BA that will soon be a WEIM participant. We request positive confirmation in the EDAM design that EDAM will allow generation-only BAs to participate in EDAM. As with WEIM, we expect that EDAM will need to make design accommodations for generation-only, “atypical” EDAM entities. We request future workshops or discussions with the CAISO to address this participant scenario.

Second, as described above, we request the CAISO hold a workshop specifically to address the participation options and obligations of independent power producer-owned generators. This workshop should cover all generator scenarios including: resources inside the CAISO, resources in a non-ISO EDAM entity, resources outside EDAM but delivering to a CAISO intertie, and resources outside EDAM delivering to a non-ISO border. It should address how these resources will or will not count in EDAM entities’ RSE, options or obligations for scheduling in the market, requirements for associated transmission, GHG bidding and deeming, the effect of export constraints on dispatch, and settlements. While some of this information is peppered throughout the EDAM proposal it should be cohesively presented in a stakeholder process that invites careful examination of impacts to third-party participation.

 

Third, Avangrid was surprised to see the draft final proposal include a new transmission requirement for supply offers. Third-party generators within EDAM entities will be obligatory rather than voluntary participants in the market. Therefore, this late change will be highly impactful. We appreciate and support that as of the November 14 workshop, the CAISO is proposing modifications to what appeared in the October 31 draft proposal so that suppliers without network resource designation or firm point-to-point service are not wholly excluded from the market. We note that even generators with substantial transmission portfolios may not have transmission that always matches 100% of their expected generation offers at all times. Within OATT territories, transmission may be scheduled or traded in a fluid manner up until the start of a day-ahead market or after. Therefore, expecting that all suppliers will have 100% transmission capacity locked-in at the time of scheduling in the EDAM would be unfair and reduce market flexibility, resulting in suboptimal outcomes. This recommendation would have been a vast overcorrection for addressing the concern of transmission free-ridership, especially given that transmission providers will be compensated in the EDAM design for use of their unsold but utilized Bucket 3 transmission. We were further concerned with the initial draft final proposal that suppliers provide transmission “to the edge of their BA” which would be highly problematic for a generator that has acquired transmission rights for a different point-of-delivery as agreed to in a long-term contract with an off-taker. The modified proposal presented on November 14 in which suppliers without 100% transmission service could instead pay a daily firm P2P rate is an improvement on the draft final proposal. However, we recommend the CAISO instead charge an hourly-rate, which would be better aligned with the actual costs and intervals of supply offers.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

No comments.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

As stated above, Avangrid Renewables has remaining concerns about loss of value in long-term OATT rights. However, we appreciate the improvements made from the original proposal for transmission availability in EDAM.

Regarding Bucket 1 transmission, the CAISO should clarify who is responsible for making Bucket 1 transmission associated with resources included in RSE available in EDAM. For a third-party resource located in one EDAM entity BA but contracted to another EDAM entity BA and delivered on the third-party’s rights, is it the receiving entity or the third-party who is responsible for making this transmission available? If it is the third-party’s responsibility, would this transmission be scheduled as in Bucket 2, pathway 1 or otherwise made available as Bucket 1?

Regarding Bucket 2, Pathway 2, we are pleased that transmission customers would be eligible for compensation directly from the CAISO rather than through an EDAM entity. This change promotes fairness and respect for OATT rights. We also appreciate the CAISO’s adjustment of the deadline in Pathway 2 from 6am to 9am, closer to the start of the DAM. However, we are still unclear as to why transmission customers couldn’t or shouldn’t have until 10am to release these rights given that the EDAM won’t seek optimize on these rights any earlier. Transmission customers often schedule and assign transmission rights right up until the start of the market and allowing for a 10am election would much better conform to current scheduling behaviors.

On Pathway 3, we appreciate the CAISO’s desire for the “EDAM transmission provider to hold the transmission customer harmless from EDAM transfer and congestion revenues resulting, by sharing EDAM transfer and congestion revenues.” This is certainly a good goal for the CAISO to set for EDAM participants. However, the CAISO acknowledges that it is not possible to discern redispatch costs that are specifically associated with later exercise of transmission rights. Thus, it may be difficult to fairly keep all customers whole. Further, it is unclear how the CAISO would obligate EDAM entities to keep transmission customers whole. Would this be part of a standard OATT update that is required for EDAM implementation? If not, we question whether EDAM entities will in fact implement this revenue sharing in a manner that appropriately respects individual transmission rights.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

No comments.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

No comments.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

Avangrid Renewables supports the proposal counting of WSPP-C firm energy contracts in RSE.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

No Comments.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

No Comments.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

No Comments.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

Avangrid Renewables requests that the final proposal define the RSE obligations for generation-only BAs who may become EDAM entities.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No comments.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

No comments.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

No comments.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

No comments.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

Avangrid Renewables remains uncertain about some aspects of the GHG accounting proposal and recommends a workshop with CARB to explore details. For example, we would like to better understand the relationship between CARB designated specified-source status and the effect of deeming and export constraints on resources located outside of but delivering into California.

We are also concerned, based on the draft final proposal and the November 14 workshop, that resources under contract to serve load in California or Washington but located outside the state might be under-dispatched by the market due to the net export constraint applied for secondary dispatch mitigation purposes. The CAISO has explained unique treatment of California RA resources delivered from outside the state but has otherwise eliminated the “GHG-pseudo tie” concept from the GHG accounting proposal. However, we believe all contracted resources should be able to be fully deemed delivered to their sink BA.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

No comments.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

No comments.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No comments.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

No comments.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

No comments.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No comments.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

No comments.

BANC
Submitted 11/22/2022, 01:46 pm

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

Contact

Kevin Smith (kevin@westernenergylaw.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

The Balancing Authority of Northern California (BANC) appreciates the opportunity to provide comments on the CAISO’s Extended Day Ahead Market (EDAM) draft final proposal (Proposal).  Overall, the CAISO continues to improve and refine its proposal in a positive direction, and its further use of examples has greatly clarified several elements, particularly in support of demonstrating how market transfers will not encroach on the individual reliability obligations of the EDAM BAAs.  BANC nevertheless does seek a couple of further clarifications and considerations herein.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

BANC is requesting clarification regarding the settlement of load in the Proposal. The Proposal states all load must be bid or self-scheduled in the market. In WEIM, load was not required to be bid into the market; therefore, load that was not bidding into the market was considered to be a non-participating resource and, as such, load imbalance energy was settled under the EIM Entity SC ID as the delta between Load Forecast (Base Schedule) and submitted meter data for each CLAP.  However, since EDAM load must be bid into the market, does it then become a participating resource?  If so, participating resources in WEIM are settled under the Participating Resource SC ID.  How will this work under EDAM?  Will load imbalance energy be settled under the EIM Entity or EIM Participating Resource SC ID? 

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

BANC agrees and supports the principle that all EDAM transfers be afforded equal priority.  BANC does expect close coordination with EDAM entities to monitor the actual implementation side of this concept, as these transfer priorities are not implemented on pro rata basis, but are often implemented, among other things, based on variables such as locational effectiveness and operator discretion.  Thus, it will be important for the EDAM entities to have confidence that priorities are truly managed on a non-discriminatory basis.

 

Additionally, based on the tiered penalty structure assigned to the RSE, the retained ability of the EDAM entity to manage its own reliability (including its ability to manage its resource above those needed for the RSE), and the WEIM constraint preventing the “simultaneous relaxation of the power balance constraint and net export transfer above the base net transfer,” BANC is generally comfortable that the design will largely manage EDAM risks related to transfers.  However, we want to see robust transfers and hope, except in these edge scenarios, the net export constraint is only used by the BAAs on a limited basis (if at all) – i.e., in edge cases only.  We do appreciate having this tool, particularly as we get familiar with EDAM, but we also hope that it will be utilized infrequently as EDAM entities become more comfortable with market performance.

 

BANC further asks the CAISO to consider the net export constraint, in conjunction with the use of Availably Balancing Capacity (ABC) in EDAM, and that ABC be included in the entity’s RSE.  This is also discussed in BANC’s response to RSE question 10, below.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

BANC supports the overall 3-bucket design, as described in the Proposal as a means of describing the various uses and const recovery mechanisms for EDAM transmission.

 

BANC further agrees with the CAISO proposal and options related to the underlying “pathways” for bucket 2 transmission held by third party customers. Under these various pathways, the transmission customer is afforded a full range of options, including the ability to derive a revenue stream from the exchange with the CAISO of unused firm transmission (of a month or more in duration) for a direct allocation of transfer revenues. 

 

BANC also believes that the pathway 3 option will in most instances preserve the transmission customer’s flexibility over scheduling their firm rights past the close of the day ahead market at 10 a.m., to the extent redispatch can accommodate the real time schedule.  As is the case today under the Federal Energy Regulatory Commission’s (FERC) pro forma Open Access Transmission Tariff (OATT), scheduling will be maintained to the extent practicable.  In the case of EDAM, practicability requires a market solution through redispatch.  BANC would expect that in most instances, such a solution will be preserved.  In rare edge cases, the rights can be preserved by scheduling prior to the close of the day ahead market.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

BANC supports the ability of the EDAM entity transmission service provider to recover revenues that are currently compensated through OATT sales and that will be lost through participation in the EDAM.  This would only constitute a small portion of overall OATT sales, since many historical sales will continue after EDAM becomes operational due to, among other things, resource adequacy and resource sufficiency obligations.  Of course, this is not the same for lost revenues to the CAISO participating transmission owners (PTOs), whose lost revenues will be due to fewer exports being assigned the wheeling access charge (WAC).  In both instances, whether EDAM transmission service providers who post ATC for sale on OASIS or PTO which recover through the CAISO WAC, they are entitled to recover lost transmission revenues due to EDAM Participation. But as an overall principle, it is essential that the transmission providers are not disincentivized from EDAM participation by not having an avenue to recover bone fide lost transmission revenues attributable to EDAM participation.

 

BANC also supports the new requirement that, in order for supplier to participate in the market, it must either be a designated network resource or obtain transmission in the EDAM entity BAA, as it currently would, in order to participate in the market.  However, BANC does not believe it is necessary to be as restrictive as the Proposal suggests with respect to the transmission procurement obligation.  For example, CAISO suggests the following requirements are to be met by the supplier:

 

  • Must be a designated network resource under the terms of the EDAM entity OATT;
  • Must reserve firm point to point transmission service of at least one month in duration to the EDAM entity border under the terms of the EDAM entity OATT; or
  • Must hold a legacy (pre-OATT) transmission contract.  Proposal at 16-17.

 

BANC notes two issues.  First, we do not believe there must be a long-term commitment to firm transmission, such as a month or more, attached to this requirement.  The main issue is protecting from free riding on the system that is currently funded through transmission sales to suppliers.  These suppliers are currently required to procure transmission to engage in bilateral sales in the day ahead market.  In other words, they cannot simply generate today and be paid at the busbar.  EDAM does not remove the underlying OATT structure.  That noted, it is not necessary to require a particular duration of transmission, provide the use is covered.  Today, a transmission provider can assess an unreserved use penalty in accordance with their OATT.  Thus, there can be other options to address free riding on the transmission system, so BANC suggests more discussion around this topic.

 

Second, BANC notes that it is not the EDAM entity OATT in all instances.  For BANC, it is the OATT holder/transmission service provider, not necessarily the EDAM entity, that administrates transmission. While BANC is likely to be the EDAM entity, it does not have an OATT.  Rather, the OATTs would be administrated separately by one of it participating transmission providers.  While this is a fairly minor point, it should be further clarified in the next version and certainly in the EDAM tariff. 

 

Finally, BANC supports the concept articulated by the CAISO (as requested by a stakeholder) that legacy agreements which expire, and therefore have no OATT sales history, should be afforded the same treatment as “new transmission.”  Specifically, the CAISO states:

 

An additional stakeholder comment on component 2 suggested the mechanism should also account for potential reduced short-term firm and non-firm transmission revenues associated with expiring legacy transmission contracts. The proposal introduces this element for further consideration. Although transmission providers make transmission service available for sale under the terms and conditions of the OATT, there are still remaining legacy transmission contracts – executed prior to the OATT – with unique terms and conditions. Over time, these transmission contracts may migrate to OATT service or otherwise expire. If a legacy transmission contract expires and is not converted to an OATT contract with that transmission customer, the transmission becomes available for sale through the OATT, and some of that released transmission might support short-term firm and non-firm sales. In the context of the EDAM, the transmission provider may also see reduced revenues from sales of non-firm and short-term firm transmission associated with the release of transmission capacity resulting from the expiration of a legacy transmission contract. These reduced revenues could be approximated based on the same methodology applied to new transmission builds by applying the ratio of the short-term firm and non-firm historical revenues to the overall transmission revenue requirement.  Id. at 51-52

Again, as noted above, the broader principle for transmission providers in EDAM is that they should not lose transmission revenues due to EDAM participation.  Moreover, for the federal power marketing agency inside of the BANC BAA, these lost transmission revenues would result in a cost shift among their customers, which would be unacceptable. Thus, we need to ensure that the transmission revenue recovery mechanism is nimble enough to address this overarching recovery principle, not so rigid it could potentially exclude unforeseen categories of losses.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

BANC recognizes that there is no perfect solution for marrying the two worlds of an LMP market and an OATT world.  Unlike a RTO, which can fully optimize unincumbered participant transmission, EDAM has to strike a balance between the existing bilateral OATT world and the CAISO’s flow-based, LMP, market structure.  Taken as a whole, the Proposal outlines a balanced and equitable treatment of all transmission rights, while ensuring that transmission cannot be strategically withheld or without imposing inefficient and potentially costly phantom congestion on load.  This is accomplished, in the case of bucket 2, by allowing the EDAM optimization to use unscheduled transmission, while in nearly all instances, affording the transmission customer to schedule its rights in real time.  Further, EDAM also provides transmission customers an option to exchange rights it does not intend to use for a direct payment of transfer revenues from the CAISO.

 

With respect to bucket 3, requiring all unsold ATC to be optimized without a hurdle rate, prevents any strategic withholding of ATC by at transmission provider. 

 

All of these transmission elements, along with bucket 1 (RSE transmission), will help to facilitate robust EDAM transfers, which is the lifeblood of the market. 

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

BANC would prefer a more precise evaluation of deliverability with respect to the RSE, however, we recognize the timing issues preclude a full SCED approach.  We do fully support the advisory sufficiency evaluations, particularly as we increase the failure consequences.  We are also quite comfortable, as noted further below, in light of the tightening of requirements for the counting of resources.  We fully recognize that there will need to be robust coordination both with the CAISO and EDAM participating entities, particularly during the first year of operations, to monitor and respond to any RSE design elements (as well as the other critical EDAM design elements) to address the nearly inevitable surprises that may arise in the course of ongoing market performance.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

BANC supports the tiered approach in the Proposal as a reasonable compromise to address various levels of RSE failures, from de minimis to more extreme. While refinements may certainly be necessary to the pricing formulations, we have concluded that a price-based penalty, as opposed to a limitation on transfers, is appropriate for EDAM start-up.  We believe the combination of financial penalties, along with tagging and other attempts to validate resources is a good, albeit not perfect, starting point.  Key will be ongoing oversight and transparent reporting on the performance of the EDAM entities and the CAISO.  Furthermore, the CAISO’s proposal to not allocate the full EDAM diversity benefit at go-live and the additional imbalance reserves requirement beyond 97.5 upwards confidence, will help to address reliability concerns.

 

That noted, BANC does seek additional clarifications around the need for the market to resolve for any entity to remain in the pool.  BANC believes that any level of failure, tier 1 through tier 3, would result in being out of the pool, if the market cannot resolve.  The tier would be established by the RSE, but an inability of the market (IFM) to cure would not be knowable at the time of the RSE.  For example, if an entity fails under tier 2, if the market runs and the deficiency cannot be cured, this would result in the entity being out of the pool.  Any penalty, however, would be set in accordance with the appropriate tier, and the penalty will be applied to the entire failure quantity.  We therefore seek clarification that any inability of the market to resolve will result in the removal of the failing entity from the pool.

 

In summary, if the market cannot cure the insufficiency, either in whole or in part, the EDAM entity will continue to be subject to the administrative surcharge depending on the magnitude of insufficiency and the respective tier, but the entity will be excluded from the pool of RSE passing EDAM BAAs and evaluated individually within the WEIM RSE, which results in the entity foregoing the diversity benefit.  Additionally, that entity will be evaluated for WEIM RSE alone.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

BANC supports the concept of pooling EDAM entities that pass the RSE.  While there will be some limitation on allocating the diversity benefit, at least at start-up, diminishing this benefit, it is a benefit nonetheless. Moreover, except under changed system conditions occurring after the day ahead test, which may require a separate test for the EDAM entity or entities in the WEIM, it makes sense to allow these entities to pass through as a group.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

BANC agrees that such a constraint may be a needed tool, particularly at start-up.  Moreover, as it is “voluntary” and set by the individual BAAs, it is not a unilateral imposition by the CAISO.  As noted above (Confidence in Market Transfers), while this is perhaps a good option for entities to gain confidence in then market, it is a two-edged sword, as it clearly can limit market liquidity if used in non-edge case scenarios. BANC hopes that over time, this tool will be used on an extremely limited basis.  It is also of note that there is no requirement that an EDAM entity offer beyond its RSE obligation, so this may not prove significant in operations. 

 

BANC also asks the CAISO to consider the application of the WEIM Available Balancing Capacity (ABC) in EDAM and that such ABC be counted towards the entity’s RSE.  While dispatchable for the needs of that BAA, it provides market visibility to all resources in the overall EDAM footprint, which BANC believes is useful to the operator. 

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

 BANC has no further comments.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

BANC fully supports the IFM and RUC design as described in the Proposal.  With respect to RUC, our support goes hand-in-glove with the ability of the EDAM entity to hold back resources not used to pass the RSE.  This alleviates the concern that a BAA’s reliability resources can be committed to serve another entity’s load to the potential detriment of its own reliability obligations.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

BANC has no further comments.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

BANC supports the CAISO’s proposal to allow the EDAM entity the choice to enable convergence bidding at their boundary.  BANC sees the value of convergence bidding, and we do have concerns regarding the asymmetry of having convergence bidding only enabled at the CAISO interties leading to unintended consequences, however, we think the implementation risks and challenges to the EDAM BAAs is greater, and it should be adopted on a timeline that comports with their ability to integrate this functionality.  We would expect close collaboration with the CAISO and the other entities soon after start-up to determine when this functionality can be added.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

BANC supports the CAISO’s proposal to limit external resource participation to pseudo-tied, dynamically scheduled, and self-scheduled contracted supply with respect to the EDAM entity BAAs at EDAM start-up.  BANC also supports, as described by the CAISO, “the ability for off system designated network resources, under the terms of the EDAM entity OATT, to bid economically at the EDAM entity intertie where it is contracted to serve load.”  Proposal at 85.  In the case of this newly added exception, it does not pose a displacement or free-rider risk because it is an identifiable resource.  Similar to convergence bidding, it is anticipated that this is largely a start-up issue and will be revisited by the CAISO and the entities after we have operational experience with the new market.  As the CAISO notes, “the later re-evaluation of external resource participation will allow consideration of the matter in conjunction with possible co-optimization of energy and ancillary services in the EDAM, which mitigates some of the reliability concerns raised by WEIM entities. Also, supply structures across the West may evolve in a manner that further mitigates the reliability concerns expressed.”  Id. at 86.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

BANC has no further comments.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

BANC has no further comments.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

BANC has no further comments.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

BANC has no further comments.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

BANC generally supports the CAISO’s bifurcation of transfer and congestion revenues and the proposed allocation.  We admit that this topic has been quite challenging, and it was conceptually difficult; however, we believe that the CAISO has provided a far better explanation of this distinction in the Proposal.  Namely, as the CAISO notes:

 

Transfer revenue is the revenue collected at transfer locations when one EDAM BAA provides energy, imbalance reserve and/or reliability capacity to another EDAM BAA, and the transfer scheduling limit is binding at the optimal solution.

 

Congestion revenue is produced by a binding transmission constraint or intertie scheduling limit (ITC/ISL) in the optimal solution such that the LMP, exclusive of Marginal Cost of Losses and Marginal GHG regulation cost, at different locations of the transmission system generally is not equal across an EDAM BAA.  Proposal, at 102, FNs 107-108.

 

BANC agrees that this distinction should be maintained for purposes of the financial administration of the CAISO’s congestion revenue rights, since we determined at the outset that EDAM should not undermine existing market instruments, such as CRRs (this same principle was also applied to the RSE, to preclude the EDAM from undermining existing/prior RA procurement obligations).  Furthermore, and perhaps more relevant to EDAM entity BAAs, if there is a binding internal transmission constraint, the market re-dispatches generation internal to the BAA to meet the BAA’s load-serving obligations.  This is a function of the internal transmission network of the BAA, and those congestion revenues should rightly accrue to the loads which are directly incurring these redispatch costs.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

BANC supports the annual UFE election, as provided in WEIM.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

BANC has no further comments.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

BANC has no further comments.

Bay Area Municipal Transmission Group (BAMx)
Submitted 11/22/2022, 11:31 am

Submitted on behalf of
City of Palo Alto Utilities and Silicon Valley Power (City of Santa Clara)

Contact

Paulo Apolinario (papolinario@svpower.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

The Bay Area Municipal Transmission Group (BAMx) is pleased to submit these comments on the Extended Day-Ahead Market (EDAM) draft final proposal.

BAMx generally supports the proposal, including for EDAM transfer revenue allocation, with a few areas of concern or that need clarification:

  1. CAISO should clarify that with WEIM and the future EDAM, there is no longer a need for the Integrated Balancing Authority Area (IBAA) treatment of any adjacent BAAs that participate in WEIM or EDAM, since the generation and transmission resources associated with these entities are appropriately valued in the WEIM and EDAM.
  2. CAISO should include a mechanism for parties with rights to or from an EDAM BAA boundary, but not across the boundary into an adjacent EDAM BAA, to settle directly with the CAISO for their share of the transfer revenues.
  3. CAISO should seek review prior to EDAM implementation by the Market Surveillance Committee, Department of Market Monitoring and Governing Body Market Expert to ensure that the ability to cure RSE deficiencies prior to running Short Term Unit Commitment will be sufficient to curb parties’ ability to exercise market power through their transmission rights to a BAA boundary, especially in light of the Bucket 2 Pathway 2 option for entities to receive transfer revenues from released unscheduled transmission. The MSC and DMM should be tasked with identifying if additional transmission market power mitigation measures are needed, such as allowing EDAM RSE failures to be cured by subjecting entities relying on EDAM transfers to a transmission charge from the transmission provider based on the daily firm point to point rate under the OATT, similar to the proposed charge for generators that exceed their transmission reservations.
  4. Transmission providers should first use congestion and transfer revenues to hedge the cost exposure related to the EDAM entity’s use of unscheduled unreleased Bucket 2 transmission, but any remaining Bucket 3 transfer revenues should be credited against the calculated lost short-term transmission revenues prior to allocating any shortfalls to the other EDAM entities.
2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

BAMx supports the voluntary participation model in the draft final proposal, including load and resource participation for entities that have chosen to participate in EDAM (EDAM Entities). BAMx supports the transmission requirements (as described in the November 14 EDAM presentation) for generation in EDAM BAAs. That is, generators need to be a designated resource, or reserve firm point-to-point transmission service (not required to be to the border) or be subject to daily firm point-to-point transmission charges. BAMx also supports the draft final proposal transitional measures.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

The draft final proposal notes that in stressed system conditions where the market utilizes all available resources to optimally address the circumstances, each EDAM entity will rely on its operational tools to manage grid conditions within its BAA. If the stressed conditions persist and there is a risk of load shedding, all EDAM entities would afford market transfers sourcing from its BAA equal priority to its load, to be curtailed on a pro-rata basis, subject to operational discretion and coordination. EDAM entities can reserve supply in excess of their RSE obligation, and can use a net EDAM export transfer constraint, to manage and respond to reliability conditions within their BAA.

BAMx does not oppose this approach, but notes that this could result in market inefficiencies if EDAM entities reserve too much excess supply or too aggressively restrict export transfers. Under the current (pre-EDAM) market construct, BAAs can curtail exports that are supported by imports across facilities that experience outages. These curtailments are proportional to the amount of energy scheduled across the curtailed intertie, not proportional to the exports’ share of BAA load plus exports. The EDAM approach places more risk on BAAs that have EDAM transfers-in supporting EDAM transfers-out than they bear today for comparable transactions, because they will no longer be able to curtail the transfers-out to the same degree. If EDAM entities take a conservative approach to managing this additional risk, it could result in a reduction in resources and transmission available for EDAM optimization for many more hours than would have been affected by relatively infrequent curtailments due to contingencies. BAMx urges the CAISO to consider whether a modified approach that allows for EDAM transfers to be curtailed in proportion to their reliance on curtailed transmission facilities would result in more efficient EDAM operations.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

BAMx supports the use of buckets to categorize the types of transmission made available under EDAM, with the transmission in all buckets being made available hurdle free. In the draft final proposal, the CAISO provided more details on how ETCs/TORs will be honored in EDAM. BAMx members have rights to the California Oregon Transmission Project (COTP) within BANC that will be affected by CAISO’s proposed treatment of such rights. BAMx supports the proposal to have three pathways for treating Bucket 2 transmission, including the ability for rights holders to utilize Pathway 3 to exercise their rights after the EDAM day-ahead market. The EDAM entity within which those rights reside would utilize accrued transfer and congestion revenues associated with the market’s use of those rights to offset any resultant redispatch costs, and would allocate shortfalls or excesses to the EDAM entity’s measured demand. Transmission Rights and Transmission Curtailment instructions should be used to ensure that real-time schedule changes are appropriately limited in instances in which the transmission facilities supporting the rights have been derated.

BAMx is concerned, however, that the draft final proposal does not appear to have a mechanism for parties with rights to or from an EDAM BAA boundary, but not through the boundary into an adjacent EDAM BAA, to settle directly with the CAISO. In these instances, the rights holder releasing rights under Bucket 2 Pathway 2 should receive the EDAM entity’s 50% share of the transfer revenues associated with the release of those rights. BAMx urges the CAISO to develop a mechanism by which such rights holders could settle directly with the CAISO for both the party’s own use of its rights and for their share of their EDAM BAA’s share of the transfer revenues associated with the use of those rights. For example, CAISO could establish an aggregate ETSR at each intertie encompassing the transfer capability associated with the intertie and identify each rights holder’s share of that aggregate ETSR. CAISO would then allocate to each rights holder their proportionate share of any transfer revenues for each aggregate ETSR. Parties with rights through the boundary (i.e., on each side of the ETSR) would thereby receive their share of 100% that aggregate ETSR’s transfer revenues, while parties with rights in only one of the two BAAs would receive their share of 50% of that aggregate ETSR’s transfer revenues.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

BAMx continues to believe that transfer revenues associated with Bucket 3 transmission should be credited against the calculated transmission provider’s lost short-term transmission revenues. CAISO noted in the draft final proposal that this transfer revenue should not be seen as a new source of revenue to offset lost transmission revenues, but instead should be seen as a source of revenue, along with congestion revenues, to hedge cost exposure for the EDAM entity’s transmission customers. BAMx agrees that the transmission provider should first use the congestion and transfer revenues to hedge the cost exposure related to the EDAM entity’s use of the unscheduled unreleased transmission, but any remaining Bucket 3 transfer revenues should be credited against the calculated lost short-term transmission revenues prior to allocating any shortfalls to the other EDAM entities.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

No comments at this time.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

BAMx is concerned about the potential for parties holding significant amounts of transmission to potentially exercise market power when that transmission is needed for the receiving BAA to meet the RSE. Requiring parties to use day-ahead eTags to demonstrate the use of firm transmission to support claimed RSE could render meaningless the only transmission market power mitigation measure that exists in the OATT (i.e., automatic release of unscheduled transmission prior to real-time). This problem is exacerbated by the Bucket 2 Pathway 2 option for rights holders to receive transfer revenues when they release the rights to EDAM (rather than sell those rights to parties that might need them to meet the RSE). A pivotal transmission supplier no longer would face the loss of value from its unscheduled transmission, so will have less incentive than it does pre-EDAM to sell unused transmission to parties that need the transmission to meet the resource sufficiency obligations under EDAM. Because uncured RSE failures could trigger tiered RSE surcharges, not making transmission available (at reasonable prices) for BAAs to pass the RSE also could have knock-on effects on capacity markets.

BAMx requests that CAISO seek review of this issue prior to EDAM implementation by the Market Surveillance Committee, Department of Market Monitoring and Governing Body Market Expert to ensure that the ability to cure RSE deficiencies prior to running Short Term Unit Commitment will be sufficient to curb parties’ ability to exercise market power through their transmission rights to a BAA boundary (e.g., BPA transmission rights to COB/NOB), especially in light of the Bucket 2 Pathway 2 option for entities to receive transfer revenues from released unscheduled transmission. The MSC and DMM should be tasked with identifying if additional transmission market power mitigation measures are needed. Such measures could include allowing EDAM RSE failures to be cured by subjecting entities relying on EDAM transfers to a transmission charge from the transmission provider based on the daily firm point to point rate under the OATT, similar to the proposed charge for generators that exceed their transmission reservations.

 

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

No comments at this time.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

No comments at this time.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

As noted in its response to Item 3, BAMx has a concern about market inefficiencies (and cost shifting) resulting from EDAM entities too aggressively restricting export transfers using the net EDAM export transfer constraint. Under the current (pre-EDAM) market construct, BAAs can curtail exports that are supported by imports across facilities that experience outages. These curtailments are proportional to the amount of energy scheduled across the curtailed intertie, not proportional to the exports’ share of BAA load plus exports. The EDAM approach places more risk on BAAs that have EDAM transfers-in supporting EDAM transfers-out than they bear today for comparable transactions, because they will no longer be able to curtail the transfers-out to the same degree. If EDAM entities take a conservative approach to managing this additional risk, it could result in a reduction in resources and transmission available for EDAM optimization for many more hours than would have been affected by the rare curtailments. BAMx urges the CAISO to consider whether a modified approach that allows for EDAM transfers to be curtailed in proportion to their reliance on curtailed transmission facilities would result in more efficient EDAM operations.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

No comments at this time.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No comments at this time.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

No comments at this time.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

BAMx supports the draft final proposal for new EDAM entities to have the choice of implementing convergence bidding immediately or to elect an optional one-year transition period prior to implementing convergence bidding.

 

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

No comments at this time.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

BAMx supports the proposal to adopt the resource-specific approach at the outset of EDAM for the reasons cited in the proposal, but urges the CAISO to continue to investigate and work with the relevant state agencies to develop the regulatory changes that would be needed to implement alternative approaches, such as the LADWP proposal. The CAISO should not wait to evaluate the EDAM GHG design until after the first year of implementation to assess what enhancements or evolution is needed.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

No comments at this time.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

No comments at this time.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No comments at this time.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

BAMx supports the draft final proposal to (1) share transfer revenue 50:50 accrued at the interties between two EDAM BAAs, and (2) assign the congestion revenues accrued resulting from congestion and constraints on the internal transmission system to remain with the EDAM entity on whose transmission system the constraint materialized.

The draft final proposal provides that the transmission customer will receive the full allocation of transfer revenue when transmission across an interface is made available under Bucket 2 Pathway 2. This approach is reasonable, but as noted in response to Item 4, BAMx is concerned that the draft final proposal does not appear to have a mechanism for parties with rights to or from an EDAM BAA boundary, but not across the boundary into an adjacent EDAM BAA, to settle directly with the CAISO. In some circumstances, such as at COB, transmission rights north of COB (e.g., John Day to Malin and/or Captain Jack) may be held by different parties than those holding the rights south of COB (e.g., COTP rights from Captain Jack to Tracy, Western PACI rights from Malin to Tracy, or Malin to Round Mountain rights). In these instances, the rights holder releasing rights under Bucket 2 Pathway 2 should receive the EDAM entity’s 50% share of the transfer revenues associated with the release of those rights. BAMx urges the CAISO to develop a mechanism by which rights holders could settle directly with the CAISO for both the party’s own use of its rights and for their share of their EDAM BAA’s share of the transfer revenues associated with the use of those rights. For example, CAISO could establish an aggregate ETSR at each intertie encompassing the transfer capability associated with the intertie and identify each rights holder’s share of that ETSR. CAISO would then allocate to each rights holder their proportionate share of any transfer revenues for each ETSR. Parties with rights through the boundary (i.e., on each side of the ETSR) would receive their share of 100% that ETSR’s transfer revenues, while parties with rights in only one of the two BAAs would receive their share of 50% of that ETSR’s transfer revenues.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

No comments at this time.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No comments at this time.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

BAMx seeks clarification from CAISO that with WEIM and the future EDAM, there is no longer a need for the Integrated Balancing Authority Area (IBAA) treatment of any adjacent BAAs that participate in WEIM or EDAM, since the generation and transmission resources associated with these entities are appropriately valued in the WEIM and EDAM. 

Bonneville Power Administration
Submitted 11/22/2022, 04:02 pm

Contact

Andy Meyers (apmeyers@bpa.gov)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

Bonneville would like to thank CAISO for their continued collaboration and dialogue with stakeholders as the EDAM market design continues to evolve and mature toward a final proposal.

Bonneville appreciates CAISO’s updates in response to our previous comments.

Bonneville generally supports the market design and framework that CAISO shared in the draft final EDAM proposal.

Bonneville has concerns regarding transmission requirements that have been updated from the previous draft.  Bonneville is aware that CAISO and stakeholders engaged in significant discussion regarding transmission requirements during the November 14th EDAM stakeholder call.  Bonneville appreciates the changes proposed during that call, but encourages the CAISO to ensure the next iteration of the EDAM proposal incorporates and documents all changes discussed around the new transmission requirement.

Bonneville supports the CAISO’s proposed equal treatment for load and EDAM exports recognizing that it provides faith in the reliability of EDAM transfers. Bonneville generally supports the proposed framework for Resource Sufficiency but requests clarification on failure consequences for the pooled WEIM. We support the CAISO’s choice to include WSPP schedule C transactions in EDAM RSE evaluation and believe that the general requirement to identify the source BA should provide sufficient information for evaluation purposes. We again encourage CAISO to consider our comments surrounding market power mitigation because we firmly believe that out of market actions should be minimized to prevent operational and market distortions. Bonneville emphasizes that additional opportunities for external resource participation should be included in the proposal to accommodate entities as they become familiar with the market and explore full participation options. Finally, Bonneville appreciates updates to the GHG framework to acknowledge state boundaries, but continues to prefer a zonal approach rather than the resource-specific approach.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

Consistent with our prior comments, Bonneville continues to largely support the voluntary participation methods surrounding market entry and exit outlined in the proposal.   We continue to appreciate the transitional measures that allow new EDAM entities to enter the market with a reduced risk of experiencing or creating adverse market impacts.  We appreciate the CAISO’s intent to clarify the type of relationship between resources in an EDAM BAA and the CAISO.  The proposal states that all resources in an EDAM BAA can either be represented by an EDAM entity scheduling coordinator or establish a direct scheduling coordinator relationship with the CAISO.  At an upcoming stakeholder meeting we encourage CAISO to provide detailed examples of both relationships which should detail activities from day-ahead to settlement.

 

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

Bonneville agrees with CAISO regarding the importance and criticality of confidence in market transfers to the overall design of EDAM.  If stakeholders lack confidence in market transfers they are not likely to be participants in the market.   As noted in our prior comments, Bonneville continues to agree that CAISO should afford the same priority for EDAM transfers as for load to ensure confidence in market transfers.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Bonneville continues to have concerns that we shared in June 2022 and in September 2022.

Bucket 1 transmission is meant to be firm or conditional firm transmission that is needed to support resource sufficiency plans, and therefore must be made available to the market in order to ensure a reliable day-ahead commitment and support confidence in market transfers.[1]  The EDAM straw proposal later proposes that WSPP Schedule C and ISO RA Import contracts, along with economic bids at the CAISO interties, should count towards meeting the EDAM Resource Sufficiency Evaluation despite the fact that the source (both resource and source BAA) and transmission are unknown at the time of the day-ahead market optimization.[2]  The allowance of any firm energy contracts that do not have identifiable firm or conditional firm transmission at the time of the day-ahead market optimization is contradictory to the foundational reasons for providing bucket 1 transmission.  Additionally, allowing these types of contracts to count towards bucket 1 transmission will likely undermine confidence in the firmness of bucket 1 transmission, and could lead to unintended consequences with the usage of bucket 2 transmission, particularly if the CAISO decides to pursue a market design that automatically assumes unscheduled bucket 2 transmission may be used for day-ahead market optimization.    Given that it is not always possible to confirm the source and establish the associated transmission in time, Bonneville requests that CAISO monitor the frequency with which transmission is not made available by the day-ahead market run and report on any impacts to market participants during those times.

Bonneville also has concerns about the EDAM presuming the availability of unscheduled transmission rights for bucket 2 transmission that a transmission rights holder does not electively donate to the market for use.  Section 1235 of the Energy Policy Act of 2005[1] prohibits the Federal Energy Regulatory Commission from forcing any electric utility or person in the Pacific Northwest to convert firm transmission rights to financial rights for Transmission contracts that were in place as of 2005.  The most recent proposal seems to address this by requiring the TSP to hold harmless any use of firm transmission rights after the day-ahead market run from EDAM transfer and congestion costs, with any shortfall or excess being borne by the EDAM entity’s measured demand. While Bonneville appreciates the CAISO’s attempt to mitigate the issue, we have concerns with this approach as well, particularly given how late in the process this requirement is being proposed. The CAISO has stated that they do not have the information necessary to identify the appropriate compensation on their end, but it is unclear whether the TSP will be able to perform that function any better. It is unclear whether using the EDAM entity transfer and congestion revenues in this way will inappropriately shift revenue allocation. It is unclear whether this process may incentivize gaming among participants. It is unclear what the magnitude of “shortfalls and excesses” might be, and whether it is fair that those be borne by measured demand of the individual EDAM entity. Bonneville urges the CAISO to work with stakeholders to establish whether the proposal is the best approach and to clarify the details around how such a process would work, such that stakeholders can determine if the proposal is feasible and does not result in unintended consequences.

Bonneville continues to have concerns about compensation for bucket 3 transmission. The proposal for bucket 3 transmission donation suggests that all ATC at the time of the day-ahead market run would be made available to EDAM for optimization.  This construct essentially diminishes the need for transmission customers to continue to purchase PTP transmission beyond their bucket 1 needs, given that the additional transmission would be made available by the TSP to the market for use.  This results in shifting transmission cost recovery onto load or creates a higher uplift charge for the market, creates uncertainty in the transmission rate recovery process for TSPs, and undermines the value of the transmission bucket construct. While Bonneville recognizes that the historical revenue recovery attempts to minimize this impact and appreciates its inclusion, we request that the CAISO continue working with stakeholders throughout implementation and beyond, and adjusting the process where necessary, to ensure all appropriate costs are recovered, cost shifts are minimized, and costs are allocated appropriately.

 


[1] 16 U.S.C. § 824r (2005).


[1] See section B.1.a.1 of the CAISO Straw Proposal – Extended Day-Ahead Market dated April 28, 2022.

[2] See section B.2.c.5.a of the CAISO Straw Proposal – Extended Day-Ahead Market dated April 28, 2022.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

Bonneville shared our concerns in the June 2022 and in September 2022 comments and continues to be concerned that transmission used by the market must be compensated at a rate that adequately covers the costs of actual or forecast transmission. Bonneville’s governing statutes require Bonneville to set rates to recover its costs in a formal administrative hearing and to equitably allocate the cost of the Federal transmission system between Federal and non-Federal power utilizing such system, and requires Commission approval of the cost recovery component of its rates. Therefore, Bonneville emphasizes that bucket 3 revenue recovery should reflect cost-causation to the extent possible. CAISO and stakeholders should continue to look for ways to improve the revenue recovery and allocation to reflect cost-causation and minimize cost shifts among customers.

 

Bonneville continues to support the inclusion of a true up, but still has concerns with what is being considered in the transmission revenue requirement with respect to the entity’s merchant.  As part of the OATT construct, PTP sales to the transmission provider’s marketing arm are equivalent to PTP sales to a third party.  Bonneville views sales made to its merchant as a recoverable cost and therefore should be considered in the calculation of the transmission revenue requirement. 

 

Additionally, Bonneville requests clarification on consideration of redirects as part of the revenue recovery. Bonneville is uniquely situated with a high volume of redirected long-term firm in lieu of short-term firm or non-firm purchases, and seeks to understand how redirects might be reflected in the recovery process.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

As noted in question one regarding our general response to the EDAM proposal, Bonneville remains concerned with the addition of a functional requirement for entities to hold monthly transmission in support of bid in transactions.  Our initial concerns are twofold;

 

  1. We are concerned with the addition of material requirements to the EDAM proposal given where things are in terms of nearing completion of the design of the EDAM framework.  The fact that CAISO elected to include a new requirement in the “Draft-Final” proposal leaves inadequate opportunity for open stakeholder discussions on this topic.  Further, the lack of details associated with the new requirements creates uncertainty for stakeholders as we try to assess the proposal as a whole and the impacts of this particular requirement.  Bonneville wants to ensure that all stakeholders have sufficient opportunity to understand and provide feedback on the requirement and that there is sufficient time to engage in transparent conversation about this requirement.  
     
  2. Of the details provided in the proposal, Bonneville has concerns with the implications of parts of the requirement. For instance, requiring the utilization of a transmission holding equal to or greater than one month seems excessive; requiring transmission to the edge of the EDAM BA may not address the “nested” BA landscape of portions of the potential EDAM footprint; requiring PTP transmission without any recognition of where that generator may sink may result in PTP requests that do not reflect actual expected transmission usage and may not compensate the appropriate parties for actual usage.

 

We recognize that open conversations since CAISO released the draft final proposal have already led to changes around the transmission requirement.  We expect those changes discussed on November 14th to be reflected in the next iteration of the EDAM proposal. We reiterate the need for CAISO to work with stakeholders to clearly establish the details of the requirements to ensure the requirement is resulting in appropriate outcomes. We request that CAISO provide additional clarification on whether transmission reservations demonstrating compliance with this new requirement need to be at a market injection point or if they can simply be anywhere on a participating EDAM entity’s system. 

 

CAISO also discussed circumstances where an entity bidding in to the market does not hold transmission and the resulting transmission charge they would incur from the market.  Bonneville requests that CAISO clarify that such a charge would be directly from the market operator and would not come from the transmission provider of the participating EDAM BAA. 

 

Bonneville would also encourage the CAISO to give some thought to periodic evaluation of the transmission revenue recovery framework.  EDAM participation may result in evolving changes and behavior in customer reservation requests which may not materialize for some time.  Long term firm reservations may not reach their rollover date until the market has been in operation for multiple years.  While there appears to be incentive for entities to rollover and continue to hold long term firm reservations it may be difficult to predict the behavior of transmission customers as they gain market experience.  Our concern is that changes in holding of long term PTP reservations may pose a potential cost shift between PTP and NT customers. 

 

Lastly, Bonneville remains concerned with the recent addition of a “make whole” directive for entities exercising their transmission OATT rights following the posting of EDAM market optimization results.  Specifically, we are concerned with the circumstance in which the EDAM BAA’s measured demand is charged to offset any shortfall needed for the “make whole” payment. 

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

Planning and balancing supply and load starts before the day-ahead timeframe. Entities need transparent Resource Adequacy requirements with clearly defined planning reserve margin requirements before the day-ahead timeframe. These requirements aid in transitioning into the day-ahead timeframe and lay the groundwork for meeting Resource Sufficiency Evaluation.

 

Bonneville agrees with the proposal for advisory runs provided by the CAISO for each EDAM participant. As noted in our last set of comments, forecasts are locked on the day before trading, Bonneville suggests that it may be beneficial for the first advisory run provided by the CAISO to run at 5 AM rather than 6 AM. Additionally, we continue to support the CAISO initiative to make available on-demand RSE testing software for use by participants.

 

In our last set of comments, Bonneville acknowledged the difficulty and complexity associated with ensuring resource delivery for RSE; and we encouraged CAISO to consider any reasonable design action that would confirm the likelihood of deliverability.  We understand that CAISO continues to recommend a design without evaluation or modeling of the deliverability for RSE.  We remain concerned that the proposed approach may not provide market participants with adequate assurances since there remains no requirement of deliverability.  We request clarification of whether or not there is validation of transmission reservations even if there is not an explicit deliverability test.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

Bonneville supports the proposed tiered approach for failure consequences, and cumulative penalties for entities that repeatedly fail RSE.  Bonneville agrees that CAISO should monitor RSE failures to determine whether failure consequences are having the intended effect of incenting forward procurement.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

Bonneville supports the proposal to pool EDAM entities passing EDAM RSE for evaluation in WEIM RSE. Bonneville requests that CAISO and stakeholders work to clarify how a failure of the pool in the WEIM RSE would play out and whether there are actions that could be taken in such a scenario to prevent reliability issues. Bonneville also suggests that CAISO and stakeholders monitor for any unexpected consequences of evaluation as a pool (e.g., lack of deliverability) that might also necessitate preventative actions.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

Bonneville supports the inclusion of a net export transfer constraint. However, Bonneville has concerns that essential supply may be held back at times of highest need and could undermine the diversity of the market when reliability is most at risk. While we recognize the CAISO’s explanation that explicit reflection of net export constraint usage in the diversity benefit is difficult, we suggest monitoring and reporting on use of the constraint and the outcomes of market optimization, both in day-ahead and through real-time, during times of scarcity. With this information, CAISO and stakeholders can understand the implications of the net export constraint in the context of RS and footprint reliability.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

We have no other comments at this time.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

Bonneville does not have any specific comments on the IFM and RUC design discussed in the EDAM straw proposal. We acknowledge that CAISO intends not to co-optimize IFM and RUC.  We recognize that IFM and RUC continue to be central components to CAISO’s DAME initiative and we have remained an active stakeholder in the DAME initiative.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

As noted in our prior response, CAISO’s approach of mitigating bids based on the mere potential of market power serves as a disincentive for supply to participate in multiple energy-related products.

Bonneville reiterates our concern that over-mitigation endangers our ability to reliably meet load obligations without over-reliance on market purchases. We request, again, the ability for entities to have their bids removed from the market run rather than be mitigated resulting in sub-optimal system dispatch.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

As noted in our prior set of comments, Bonneville supports CAISO’s cautious approach toward implementing convergence bidding in EDAM. We recognize the important role convergence bidding plays in organized energy markets, and we believe the transition period is appropriate to ensure that market participants understand its nuances. We recognize that some entities provided an indication that they might elect to establish convergence bidding at the onset of their participation in the market.   We support the optionality being offered by CAISO to each market potential market participant. 

 

We continue to support the CAISO’s interest in closely monitoring the effects of implementation across the EDAM footprint, especially that relationship between the ISO BAA (with convergence bidding) and those EDAM BAAs without convergence bidding. Bonneville continues to request an explanation of why convergence bidding is not allowed at intertie locations between EDAM BAAs, and between EDAM and non-EDAM BAAs.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

Bonneville appreciates CAISO’s modifications to the proposal to include economic bidding for external resources that are NT resources serving load in EDAM BAAs. While recognizing the inclusion of NT resources for economic bids as an improvement, Bonneville asserts that eligible external resources should also include system sales or grouped resources that are modeled in the WEIM. Such system sales are proven reliable assets that should be eligible for external resource participation. In conversation with the CAISO, it seems CAISO intends to allow system resources or grouped resources modeled in WEIM to participate, and Bonneville requests that this inclusion be reflected in the final proposal.

 

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

Bonneville appreciates the CAISO’s update to the final proposal to limiting the GHG attribution to the net export transfer.  Bonneville notes that while this update generally shifts the GHG accounting design in the correct direction, there is a need for additional discussion with stakeholders to fully understand implications and nuances of this design, including the exception for the RSE. Bonneville is concerned providing an exception to this constraint on GHG attribution in the event a BAA fails the RSE is an inappropriate solution.  It would be appropriate to allow imports, but such imports should be treated as unspecified source.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

As stated in previous comments, Bonneville generally supports this approach as a sensible solution for establishing a baseline given the CAISO has opted to adopt the resource specific approach.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

As stated above, BPA appreciates the CAISO’s efforts to limit the GHG attribution to the net export transfer and not allow for GHG attribution when a BAA is importing.  While this may result in a higher marginal GHG price, this is appropriate as it is more reflective of state carbon pricing policies.  The market should reflect those state program requirements and guidance from state regulators to reflect the state’s determination how to appropriately balance costs to the state’s ratepayers versus sufficiently minimizing emissions leakage.  It is not the role of the market operator or other stakeholders to determine this balance and it seems arbitrary for the CAISO to determine on its own that the cost is too high. 

However, Bonneville is concerned that turning off the net export constraints in hours where an EDAM BAA fails the RSE is inappropriate and risks the integrity of the GHG accounting limitations on secondary dispatch.  Bonneville feels it would be more appropriate to explore options for unspecified source imports of power to the GHG zone in instances where there are not sufficient eligible GHG bids.  Bonneville questions whether issues of having sufficient GHG bids become more persistent in the future as compared to the analyzed EIM window of July to September 2022.  Bonneville posits that any changes in participants in the markets as well as inclusion of GHG bids to accommodate Washington’s cap-and-invest program in the future could significantly influence these outcomes, leading to use of exceptions to limit the constraints becoming more frequent. 

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

The CAISO also stated in the November 14 workshop that it would look at the GHG accounting approach a year into EDAM.  Bonneville hopes the CAISO intends this review to extend to the EIM as well.  Bonneville asks the CAISO to publicly share data on performance of the GHG accounting design with stakeholders, including analysis around use of limitations of the constraints and impacts to reliability.  Bonneville also suggests the CAISO carefully considers any determinations made by or input from CARB pertaining to the ability for the design to meet cap-and-trade program requirements. 

 

Finally, Bonneville appreciates the CAISO’s recognition of the unique circumstances that accompany attempting to delineate the GHG zone for a multistate BAA.  Bonneville looks forward to working with the CAISO when Washington begins rulemakings to establish the long-term treatment of organized market imports into the state.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

Bonneville continues to support transfer and congestion revenues allocation methodologies that result in distributing revenues to the entity making transmission available to the market. Our previous comments submitted in June 2022 supported compensation to the entity that makes transmission available to the market and is used by the market. Further, we suggest that the CAISO consider implementing a simple consistent uniform process for allocation and sub-allocation of transfer and congestion revenues based on load cost ratio.  Additionally, we believe that a detailed example of the allocation of transfer revenue would benefit all stakeholders.  We request that the CAISO consider putting an example together detailing Transfer Revenue allocation at Malin. 

Bonneville does have concerns about congestion due to an OATT customer exercising/utilizing their transmission rights following the posting of market optimization results.  Specifically, as noted in several of our prior responses, we remain concerned that with potential charges to measured demand to fund the make whole payment to the transmission rights holder.  We encourage CAISO to consider this, and if necessary engage stakeholders in conversation, prior to the release of the final EDAM proposal.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

Bonneville appreciates that the CAISO identified the numerous settlement categories and described the intended calculation of each category identified in the straw proposal. It is clear that settlement will continue to remain a complex and complicated feature of the market. Bonneville does not have any explicit feedback at this time.  As the EDAM market framework continues to finalize we further advocate for detailed examples of settlements for stakeholders. 

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

Bonneville continues to appreciate the CAISO’s specificity of expected EDAM onboarding costs to be approximately $1,200,000 per entity. This figure appears reasonable and in line with cost experienced by entities when joining the EIM market. Bonneville requests that the CAISO commit to providing an updated estimate of the start-up costs at the time of signing the Implementation Agreement based on the known complexity of the joining entity. We accept the proposed requirement of an initial deposit followed by incremental deposits. We appreciate the CAISO’s clarification that once a party transitions to EDAM they will only pay the EDAM administrative fee and will no longer pay the EIM administrative fee. We also appreciate the clarification that as EDAM participation increases there is an expectation that EIM administrative fees will decrease due to increased volumes.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

As Bonneville continues to evaluate all day-ahead market opportunities, we believe that there is an increased likelihood that multiple day-ahead market initiatives will be successfully implemented in the western interconnection. Bonneville is uniquely situated in the west in that we have preference loads in eight adjacent BAAs. As such, our evolving belief is that some Bonneville loads may be outside any day-ahead market, some Bonneville loads may be inside a  day-ahead market in which Bonneville is not a participant, and, if Bonneville chooses to participate in a day-ahead market, Bonneville loads will be in that day-ahead market . A potential outcome as just described highlights the fact that Bonneville will need to be informed of all market rules and structures in order to ensure we appropriately serve our loads throughout the Northwest. Bonneville believes that “seams” between markets will be an increasingly important topic as all day-ahead market initiatives continue to advance and mature. Seams issues may include differences in transmission operating rules, power market design, scheduling practices, settlement practices, resource adequacy programs (e.g. the Western Resource Adequacy Program), etc. Bonneville suggests that the CAISO and other market initiatives be open to discussions to identify and address “seams” issues as soon as practical.

Brookfield Renewable
Submitted 11/22/2022, 04:13 pm

Contact

Steve Greenleaf (Steve.Greenleaf@brookfieldrenewable.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

Brookfield Renewable Trading and Marketing LP (Brookfield Renewable or Brookfield) appreciates the opportunity to submit comments on the CAISO’s Extended Day-Ahead Market (EDAM) draft final proposal. As a general matter, Brookfield supports the expansion of structured markets across the West so long as those markets continue to support bilateral market transactions and the ability of third-party suppliers and load-serving entities like Brookfield with the ability to satisfy their contractual obligations. Those obligations include the delivery of clean, GHG-free power to customers. In support of its obligations, Brookfield has secured long-term firm transmission rights under various open access tariffs (OATTs) and utilizes the high-priority wheel-through capability on the CAISO system in order to reliably deliver power to its customers. Securing and maintaining those rights is imperative to Brookfield’s business model and therefore it is critical that the EDAM – or any other - market structure honor those rights, both with respect to the ability to utilize (schedule) those rights in the day-ahead and real-time markets, as per the applicable tariffs, but also with respect to cost. Brookfield has made substantial financial commitments to secure those rights and should not have to pay more to utilize those rights under EDAM.

To that end, Brookfield requests that, as the CAISO continues to move toward CAISO Board of Governors and EIM Governing Body approval of the EDAM proposal, it facilitate additional technical workshops so that participants can fully understand the scheduling and settlement details of the EDAM proposal. While Brookfield very much appreciates the efforts of CAISO staff to date to detail the proposed requirements and provide examples, additional detail would be helpful in informing Brookfield’s final position on the proposal. Specifically, Brookfield requests that the CAISO dedicate a workshop to third-party participants (load and generation) and how such participants would schedule and settle under the EDAM design and what information (in the form of schedules, bids, forecasts, etc.) and the timing of such, that such entities must either provide to either the CAISO or their host EDAM Entity (Balancing Authority Area or BAA) in order to either utilize their existing rights or directly participate in the EDAM. While the EDAM model, and much of the discussion, has been focused on BAA-BAA interactions and impacts, there are many third-party customers, generators, and load serving entities within those BAAs who would benefit from such a focused discussion. Brookfield appreciates that, by design under EDAM, the CAISO defers to other EDAM entities to make necessary changes to their OATTs with respect to the interaction with transmission and other customers on their systems. Nonetheless, Brookfield suggests that beginning discussion of those details now is important to develop a complete understanding of the EDAM proposal. Brookfield also notes that such discussions will help inform Brookfield’s decision whether to act as its own EDAM Scheduling Coordinator (SC) or work through the EDAM Entity SC. 

Finally, Brookfield requests that the CAISO provide additional detail regarding the interoperability between the EDAM design and the Western Resource Adequacy Program (WRAP). While the EDAM design is predicated on each BAA retaining and maintaining its own resource adequacy obligations, WRAP includes provisions for both “holding back” and providing capacity to other BAAs in the operational timeframe. It will be important to understand how the EDAM design can accommodate this functionality and how WRAP impacts the RSE and other elements of the EDAM design.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

Brookfield supports the proposed voluntary participation model with voluntary entry and exit with a six-month notice period and no exit fees. Brookfield also supports the option of third-party participants being able to act as their own SC or work through the EDAM Entity SC.  As stated by the CAISO, “The ISO can also enable individual load serving entities within the EDAM BAA to represent their demand in the market separately from the rest of the BAA’s load. The individual load serving entity would need to work with the EDAM entity and the ISO through the implementation process to model its load separately.” Brookfield requests that the CAISO clarify, outside of more general scheduling/bidding responsibilities, the responsibilities of an LSE acting as its own SC as comparted to the EDAM Entity SC. In particular, would a third-party SC be responsible for passing the RSE or would that obligation remain with EDAM Entity SC and the third-party SC would thus have to coordinate/share information with the EDAM Entity SC.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

No comment.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Brookfield continues to recommend that the CAISO permit “Bucket 2” rightsholders that elect to release their transmission to the market (Pathway 2) be able to “bid” that transmission at a pre-established hurdle rate.  Brookfield continues to believe that permitting third-party rightsholders to collect payments above and beyond potential transfer revenues creates appropriate incentives to make their transmission available to the market and would permit them to better manage their potential cost exposure, over the long-term, to redispatch/uplift costs they may incur under Pathway 3 (i.e., when they do not utilize or offer their rights to the market in the day-ahead, but instead wait until real-time to use their rights and the CAISO must redispatch to accommodate that usage). 

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

No comment.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

No comment,

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

See comments above regarding SC responsibilities.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

See above comments regarding SC responsibilities. Brookfield requests clarification on the potential impact of RSE failures on thirty-party LSEs acting as their own SC. 

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

See above comments.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

No comment.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

No comment.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No comment.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

No comment.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

Brookfield believes that convergence bidding is an important element in any market design and can appropriately discipline load and resource scheduling in the day-ahead market.  That said, Brookfield does not oppose the CAISO’s proposal to not require EDAM Entities outside of the CAISO to implement convergence bidding on day-one of the market and to elect, if requested, a one-year transition period. Brookfield requests that the CAISO monitor and report on load and resource bidding behaviors of EDAM Entities and, as necessary, implement convergence bidding earlier than planned.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

No comment.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

No comment.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

No comment.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

No comment.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No comment.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

No comment.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

No comment.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No comment.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

No comment.

California Community Choice Association
Submitted 11/22/2022, 03:35 pm

Contact

Lauren Carr (lauren@cal-cca.org)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the Extended Day-Ahead Market (EDAM) Draft Final Proposal. CalCCA generally supports the EDAM proposal subject to the recommendations made herein. However, significant questions remain relative to how elements of the proposal will work for the California Independent System Operator (CAISO) balancing authority area (BAA), given the CAISO is in the unique position of having dozens of load-serving entities (LSEs) operating within its BAA. The CAISO should begin its CAISO BAA-specific initiative and resolve the open issues relative to the CAISO BAA in that forum before finalizing the EDAM proposal.  

Resource Sufficiency Evaluation (RSE) 

CalCCA supports the proposed application that the CAISO will use to conduct EDAM RSE and how the proposal defines RSE-eligible resources, including:   

  • Allowing non-resource-specific firm energy contracts to count towards the EDAM RSE, with tagging requirements and the ability to cure by the Short-Term Unit Commitment (STUC) run if the non-resource-specific import is not tagged by the initial deadline;  

  • Allowing economic supply offers associated with a forward contract from a non-EDAM BAA to count towards the EDAM RSE; and  

  • Including proxy demand response in the EDAM RSE and including reliability demand response in the EDAM RSE only if the CAISO BA fails the RSE without it.  

CalCCA supports the proposal to require e-tags for imports used in the RSE as long as any RSE deficiencies caused by imports not tagged can be cured by the STUC run. However, CalCCA also understands parties’ concerns that the e-tagging requirements to demonstrate firm transmission may introduce the ability for parties to exercise transmission market power. The CAISO must allow for an investigation of the ability to exercise transmission market power prior to the implementation of EDAM. The CAISO Department of Market Monitoring (DMM) and the Market Surveillance Committee (MSC) should conduct this review and opine on the need for additional transmission market power mitigation measures.  

Many other elements of the EDAM RSE proposal have not reached resolution, particularly regarding how they will work for the CAISO BAA given the multiple LSEs within the CAISO BAA. The CAISO proposes to allocate costs of curing RSE insufficiencies through EDAM first to LSEs that contributed to the RSE failure and then to all LSEs pro-rata. While CalCCA supports allocating curing costs first to LSEs that contribute to the RSE failure in concept, many open questions require resolution before taking a position on the EDAM RSE proposal. These questions include:  

  • What defines an LSE’s contribution to an RSE failure (e.g., using Resource Adequacy (RA) showings, RA outages, etc.)? 

  • If the CAISO BAA fails the advisory or binding EDAM RSE, how will the CAISO identify the LSEs that caused the failure?  

  • Following a failure of the advisory EDAM RSE, will the LSEs causing the failure be notified they are the cause of the failure such that they have an opportunity to make additional supply available before the binding EDAM RSE? 

  • Upon an RSE failure, how will the CAISO BAA or its LSEs decide whether to cure from the EDAM or be held out of the pooled Western Energy Imbalance Market (WEIM) RSE?  

  • How will the CAISO allocate to LSEs the revenues resulting from EDAM RSE failures in other BAAs? 

The CAISO indicates that it will address how it will handle the CAISO BAA failure consequences and cure processes as well as the distribution of revenues from other BAAs’ failures in a subsequent stakeholder initiative. It is difficult for California LSEs to take a position on the EDAM RSE proposal without understanding how these elements will work for the CAISO BAA and its LSEs. The CAISO should allow for the CAISO BAA-specific initiative to take place before finalizing the EDAM proposal. 

Net EDAM Export Transfer Constraint 

CalCCA supports in concept the proposed net EDAM export transfer constraint that would allow an EDAM BAA to set a limit on the amount of supply that is made available to support EDAM export transfers. For the CAISO BAA, this proposal will allow the preservation of RA capacity to support grid reliability during contingencies or stressed system conditions. Further development is needed, however, to determine under what conditions the CAISO BAA will apply the net export constraint and how the CAISO BAA will derive the constraint limit. The CAISO should include this topic in scope of the CAISO BAA-specific initiative and allow this initiative to take place before finalizing the EDAM proposal.  

Transmission Commitment 

CalCCA supports the CAISO’s proposal to automatically make unscheduled transmission available to the EDAM on a hurdle-free basis. Allowing transmission rights holders to voluntarily make transmission available could diminish EDAM benefits by restricting the amount of transmission available to the market and could result in withholding of transmission in the event a small number of entities hold the rights to a majority of the transmission. Automatically releasing unscheduled transmission will ensure EDAM BAAs unlock the full economic benefits of day-ahead market participation. 

The CAISO proposes to offer transmission revenue recovery for estimated foregone revenues from short-term point-to-point transmission revenues, wheeling access charge revenues, new transmission builds, and wheels in excess of the EDAM entity’s total net imports/exports. While making transmission available to the EDAM on a hurdle-free basis may result in a reduction in transmission revenue relative to historical revenues, transmission revenue recovery should be a transitional mechanism only, accompanied by a sunset date such that the proposal does not introduce indefinite uplift payments.  

CalCCA continues to question the need to make costs associated with new transmission build eligible for transmission revenue recovery. The CAISO proposes to allocate costs through uplifts assessed either to gross load across the footprint or to demand plus supply across the footprint. This methodology does not consider, however, the extent to which the EDAM BAAs paying for the transmission revenue recovery benefit from the new transmission build. As the BAA with the most load, CAISO’s LSEs are at the greatest risk of paying the majority of uplift charges for new transmission that it does not benefit from or benefits from less than other EDAM BAAs. Additionally, under a future EDAM, entities should factor in the overall costs and benefits of EDAM when making decisions around new transmission build. A transmission revenue recovery payment associated with new transmission build is not necessary under an EDAM construct. 

Greenhouse Gas (GHG) Accounting  

CalCCA remains supportive of the resource-specific approach to GHG accounting for initial EDAM implementation. The resource-specific approach has worked for years in the WEIM, allowing the market to optimize resources based on GHG costs reflected in their bids. Importantly, the California Air Resources Board (CARB) has accepted the resource-specific approach. Any future modifications to the resource-specific approach for EDAM, or any deviations from the resource-specific approach, will similarly need CARB to accept them. 

However, CalCCA remains concerned that the proposed approaches for limiting secondary dispatch will limit transfers from non-GHG regulation BAAs that are net importers to GHG regulation BAAs. This could limit the use of resources available to transfer into GHG areas, impacting California reliability. The Market Surveillance Committee expressed the same concerns at its October 21, 2022 meeting.1 The CAISO should continue to further analyze these concerns before finalizing the GHG accounting design.  

[1]           http://www.caiso.com/Documents/ExtendedDay-AheadMarketGHGMSC-Presentation-Oct21_2022.pdf

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

See response to question 1.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

See response to question 1. 

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

See response to question 1. 

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

See response to question 1. 

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

See response to question 1.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

See response to question 1. 

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

See response to question 1. 

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

See response to question 1. 

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

See response to question 1. 

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

See response to question 1. 

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

See response to question 1.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

See response to question 1.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

See response to question 1.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

See response to question 1.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

See response to question 1.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

See response to question 1.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

See response to question 1.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

See response to question 1.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

See response to question 1.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

See response to question 1.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

See response to question 1.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

See response to question 1.

California Department of Water Resources
Submitted 11/22/2022, 03:02 pm

Contact

Rodrigo (rodrigo.avalos@water.ca.gov)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

CDWR overall supports the EDAM initiative. In general, CDWR expects that the EDAM will lower costs through better coordination and optimization of the day-ahead market. Along with lower costs, the overall West will benefit from increased system reliability.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

CDWR agrees that the participation model should be voluntary with a 6-month entrance and exit period. 

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

CDWR supports that BAA native loads have equal priority to EDAM transfers (exports or wheel-throughs) under severe emergency conditions.  Under severe conditions, where there is a risk of load shed in a BAA, priority should not be given to export transfers (meaning that load is curtailed ahead of export transfers).   The burden of reducing load or curtailing exports under limited transmission capacity should be distributed evenly (load and exports curtailed in equal amounts).

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

No Comment.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

No Comment.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

No Comment.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

No Comment.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

The proposal indicates that the CAISO will undertake an initiative that will consider potential enhancements to the CAISO tariff and processes to enable curing of EDAM RSE failures and allocation of revenue and surcharges. CDWR supports such an effort that will address some of the complexities expressed (such as impact on the existing substitution mechanism and RAAIM) in its comments on the previous revised straw proposal in this regard.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

CDWR supports proposed net EDAM export transfer constraint provided it will not impact the RA MOO.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

No Comment.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

No Comment.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No Comment.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

No Comment.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

No Comment.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

No Comment.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

No Comment.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

No Comment.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

No Comment.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No Comment.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

CDWR supports the CAISO’s draft final proposal as follows:

  1. The transfer revenue accruing at the interfaces is shared 50:50 between the two EDAM entities that brought transmission to the EDAM market interface.
  2. The transmission owner receives the full allocation of transfer revenue associated with its transmission rights released to the market.
  3. In unique instances where the sharing of transfer revenue 50:50 between two EDAM BAAs does not align with existing or future commercial arrangements between the two BAAs (i.e., specific contracts between the entities), different transfer revenue sharing arrangements proposed by the CAISO and market participants could be accommodated.
  4. The congestion revenue accruing because of binding transmission constraints on the internal transmission network of the EDAM entity be fully allocated to the respective EDAM entity.

 

If in the future CAISO decides to implement an EDAM CRR design, CDWR's position is that it should avoid the burden on load demand that currently happens in the Day Ahead Market CRR design. CDWR would like to maintain the right to further comment on any other developments of the EDAM CAISO proposal.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

No Comment.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No Comment.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

No Comment.

California Efficiency + Demand Management Council
Submitted 11/22/2022, 03:29 pm

Submitted on behalf of
California Efficiency + Demand Management Council

Contact

Luke Tougas (l.tougas@cleanenergyregresearch.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

The California Efficiency + Demand Management Council (Council) thanks the CAISO for the additional clarity it provided in the draft final proposal with regard to the treatment of demand response (DR) and load management resources, and requests the CAISO clarify or address the following issues:

  • The Council recommends the CAISO consider allowing EDAM Entities to utilize Distributed Energy Resource Aggregations (DERA) to meet the Resource Sufficiency Evaluation (RSE) or reduce the demand forecast. 
  • As an initial step to verify whether non-conforming DR is being dispatched in accordance with EDAM Entity commitments to reduce the RSE, the Council recommends an initial, back-of-envelope approach whereby an EDAM Entity’s actual load is compared to its demand forecast minus its claimed non-conforming DR load curtailment. 
  • All EDAM Entity Reliability Demand Response Resources (RDRR) should be afforded the same treatment as the CAISO proposes for RDRRs located within the CAISO BAA. 
  • The Council requests clarification on the Residual Unit Commitment (RUC) obligations of Proxy Demand Resources (PDR) shown by an EDAM Entity to meet its RSE, specifically, how long-start resource PDRs, which cannot dispatch in the real-time market, would be treated in this context. 
2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

The Council reserves comment.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

The Council reserves comment.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

The Council reserves comment.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

The Council reserves comment.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

The Council reserves comment.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

The Council thanks the CAISO for providing additional clarity in this proposal with regard to the treatment of load modification/demand response (DR) programs.  The Council supports the use of non-conforming DR to reduce the RSE that is linked to a requirement that it be dispatched during the hours for which it is being claimed.  EDAM Entities have large amounts of DR that can provide value in meeting their respective RSEs, even if they are not formally integrated into the CAISO market as Proxy Demand Resources (PDR) or Reliability Demand Response Resources (RDRR).  In addition, by allowing EDAM Entities to develop and put forth their own PDRs and RDRRs to meet the RSE, this will hopefully motivate the development of additional market-integrated DR that will be used to meet, rather than reduce, the RSE.  The Council recommends the CAISO also consider allowing EDAM Entities to utilize Distributed Energy Resource Aggregations (DERA) to meet the RSE as well or at least reduce the demand forecast.  Though California Public Utilities Commission (CPUC)-approved rules do not yet exist for DERAs to be considered capacity resources, it is not clear in the proposal that a resource must be a capacity resource to count in the RSE, only that it meets the day-ahead market bidding and RUC availability requirements spelled out in the proposal. 

The Council would also like to address the element of the proposal that the CAISO may use RDRRs that do not bid into the day-ahead market to reduce its demand forecast should the CAISO be in danger of not meeting the RSE.  The Council recommends that this treatment be afforded to other EDAM Entities whose RDRRs are located outside of the CAISO BAA.  To the Council’s knowledge, RDRRs are subject to the same requirements and would be used the same way regardless of whether they are located within or outside the CAISO, so it is not clear why the CAISO should be able to utilize its RDRRs in a way that other EDAM Entities may not.  If the Council’s understanding of the CAISO’s intent is incorrect, then clarification in the final proposal would be helpful.

During the CAISO’s November 14 stakeholder call, it noted that it had not yet fully considered how it would verify whether non-conforming DR used to reduce an EDAM Entity’s demand forecast was delivering the load curtailment during its committed hours.  The Council recommends the CAISO proceed carefully when addressing this issue in the future and avoid creating an overly burdensome process akin to California’s DR Load Impact Protocols to verify the delivered load curtailment.  As an initial, back-of-envelope approach, the CAISO might simply compare an EDAM Entity’s actual load to its demand forecast minus its claimed non-conforming DR load curtailment.  Load is unavoidably variable to a certain extent which will limit precision, but this simple approach may at least provide an indication that the non-conforming DR was dispatched and delivered load curtailment at least roughly commensurate with the EDAM Entity’s commitments.

Finally, the Council requests clarification on the obligations of PDRs shown by an EDAM Entity to meet its RSE.  The proposal states that all EDAM entities that submit a DAM energy bid must also submit a bid for a matching quantity of reliability capacity in the RUC process of the day-ahead market.  The Council requests the CAISO specify how long-start resource PDRs, which cannot dispatch in the real-time market, would be treated in this context. 

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

The Council reserves comment.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

The Council reserves comment.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

The Council reserves comment.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

The Council reserves comment.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

The Council reserves comment.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

The Council reserves comment.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

The Council reserves comment.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

The Council reserves comment.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

The Council reserves comment.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

The Council reserves comment.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

The Council reserves comment.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

The Council reserves comment.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

The Council reserves comment.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

The Council reserves comment.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

The Council reserves comment.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

N/A

California ISO - Department of Market Monitoring
Submitted 11/22/2022, 03:14 pm

Contact

Ryan Kurlinski (rkurlinski@caiso.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

The text of DMM's complete set of comments is included in this General Comments section.  For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

Comments on Extended Day-ahead Market

Draft Final Proposal

Department of Market Monitoring

November 22, 2022

Summary

The Department of Market Monitoring (DMM) appreciates the opportunity to comment on the Extended Day-ahead Market – Draft Final Proposal.[1]

  • In previous comments, DMM has described how the day-ahead imbalance reserve product included in the EDAM design will not be sufficient for ensuring sufficient resources for each EDAM balancing area in real-time.[2]   The draft final proposal addresses this concern by allowing each BAA to set a net EDAM export constraint at a level designed to maintain the capacity necessary to meet its own reliability needs given inherent uncertainty between the day-ahead and real-time markets. DMM recommends that the tariff or BPM specifications for setting this net export constraint not be so prescriptive as to prevent each balancing area’s operators from incorporating into the net export limit a conservative (i.e. high) estimate of the uncertainty in the balancing area’s specific resource mix that gets bid into the EDAM on a particular day. 
  • While the net export constraint can protect a BAA from being exposed to reliability risks from other EDAM BAAs’ capacity shortfalls, the net export constraint does not directly prevent other BAAs from seeking to rely on EDAM rather than procuring sufficient supply in advance of the EDAM.  Based on DMM’s understanding of the draft final report, if a BAA anticipates excess supply being made available by other EDAM BAAs, the resource sufficiency evaluation failure consequences may not create additional incentives for a BAA to procure sufficient supply in advance of the EDAM market to meet its own load and uncertainty.  As a result, DMM suggests that stakeholders may want to consider revising consequences of failing the EDAM RSE to provide a stronger incentive for each BAA to procure sufficient capacity to meet its load and uncertainty rather than relying on EDAM to meet its reliability needs.
  • DMM supports the ISO’s proposed resource specific approach to greenhouse gas (GHG) accounting.  However, DMM continues to recommend that the ISO consider LADWP’s proposed variation of the resource specific approach as a future enhancement. 
  • DMM requests clarification of numerous other aspects of the draft final proposal, as described in these comments.

Comments

  1. Confidence in market transfers

Net export constraint is a critical aspect of overall EDAM design

DMM supports the proposal to allow each EDAM balancing authority area (BAA) to utilize a net export constraint to determine hourly limits on net exports of EDAM energy, imbalance reserve up (IRU) and reliability capacity up (RCU).  DMM recommends that tariff requirements for specifying how each BAA will derive the final limit each hour not be too prescriptive, so that each balancing area’s operators have the discretion to reduce the limit as they see fit under tight conditions to account for uncertainty in their balancing area’s resource mix.  We provide more detail on these views below.   

In the draft final proposal, the ISO has clarified that it intends for the real-time market optimization to prioritize EDAM transfers of energy, imbalance reserve up (IRU) and reliability capacity up (RCU) over native load.  Given imbalance reserve and EDAM resource sufficiency evaluation (RSE) design described below, the proposed net export constraint is a critical aspect of the overall EDAM design.  Situations can arise in tight system conditions in which a balancing area may need to rely on carefully setting the net export constraint to limit EDAM energy, IRU, and RCU transfers to only the amount of capacity that balancing area operators are confident is in excess of what its balancing area may need to meet its own load and uncertainty.

In previous comments, DMM has described how the day-ahead imbalance reserve product included in the EDAM design will not be sufficient for ensuring sufficient resources for each EDAM balancing area in real-time.[3] With the addition of the net export constraint, each balancing area will be able to maintain the capacity necessary to meet its own reliability needs given inherent uncertainty between the day-ahead and real-time markets.  The constraint can be utilized in tight system conditions to prevent a balancing area from having to rely on imbalance reserves procured within its area or from another EDAM balancing area.  This will be critical in tight system conditions because imbalance reserves procured to meet the 97.5% level of uncertainty will not be sufficient to ensure reliability in 2.5% of days under tight system conditions.[4]

As described in the section of these comments on the EDAM resource sufficiency evaluation (RSE), the current EDAM RSE design appears to allow EDAM balancing areas that are short on capacity to schedule EDAM energy, IRU, and RCU capacity from other balancing areas up to the quantity that those other balancing areas make available to the EDAM.  For a balancing area that allows virtual supply, this may create capacity shortfalls and reliability concerns for the source balancing area, as described in more detail below.  Therefore, in the absence of further refinements to the EDAM RSE design, the net export constraint will be a critical tool for preventing the EDAM from transferring capacity needed by a resource sufficient BAA to a resource insufficient BAA.

Given the important nature of the net export constraint to the reliability of an EDAM BAA in tight system conditions, it will be critical that each area be allowed and prepared to set the net export constraint for energy, IRU, and RCU each hour in tight conditions to only allow EDAM transfers out of capacity that is in excess of what the BAA may need to meet its own load and uncertainty.  The draft final proposal specifies that each EDAM BAA must “describe either in its OATT or business practice manuals (a) the formulation for deriving the confidence factor applicable to non-RSE eligible bid in supply and (b) factors/criteria for deriving the additional margin that further reduces the constraint limit”.[5] 

DMM recommends that these specifications not be so prescriptive as to prevent each balancing area’s operators from incorporating into the net export limit a conservative (i.e. high) estimate of the uncertainty in the balancing area’s specific resource mix that gets bid into the EDAM on a particular day.  For example, operators may need the discretion to create more additional margin on a day when larger, older, less reliable gas units bid into the EDAM than on a day when such capacity is on outage and not bidding in.  More specifically, operators must be able to use a conservatively high upper bound for the load forecast and a conservatively low lower bound for available capacity each hour on tight days to ensure that the level of capacity exported as EDAM energy, IRU, or RCU would not undermine standard reliability criteria for the balancing area, such as loss of load in less than 1 day every 10 years.

Clarify how real-time penalty prices will be set to ensure the delivery of EDAM imbalance reserve and reliability capacity awards in the real-time market

The proposal states that in “stressed system conditions, after WEIM has exhausted available supply, the WEIM will signal infeasibility by relaxing the power balance constraint in the BAA with insufficient supply”.[6] The draft final proposal is not clear on how the ISO will implement penalty prices in the real-time market so that a BAA that was scheduled in EDAM to provide IRU or RCU to another BAA can send that energy to the other BAAs in real-time while facing a power balance constraint violation in its own BAA.  

The final example in section II.2.(b) of the draft final proposal shows EDAM awarding imbalance reserve up capacity from BAA C to BAA B, and reliability up capacity from BAA C to BAA A. [7]   In real-time, when large load uncertainty is realized in BAA C, the example shows BAA C actually delivering the energy from the EDAM imbalance reserve award to BAA B and actually delivering the energy from the reliability capacity up award to BAA A.  The ISO provided additional details of the proposed changes to the mathematical formulation of the WEIM “confidence in transfers” power balance constraint presented on page 70 of the ISO’s September 7-8 EDAM slide presentation.[8]   

Based on this information, DMM understands that including the EDAM IRU and RCU awards in the positive base net transfer definition in real-time will cause the WEIM power balance relaxation constraints to not prevent IRU and RCU awards from leaving a balancing area, such as BAA C in the example.  Before this adjustment to the positive base net transfer definition, BAA C’s power balance relaxation constraint would have by itself prevented the real-time delivery of the IRU and RCU awards if that delivery would cause BAA C to have a power balance constraint relaxation.  However, it is not clear that the real-time optimization would not still choose to keep the energy in the source balancing area of the IRU/RCU (i.e. BAA C), and allow a power balance constraint relaxation in an area that was supposed to receive the IRU or RCU (BAA A or B), due to the interaction of other penalty parameters in the real-time market.

In these examples, the market software must choose between a power balance violation in the source BAA of the IRU/RCU (BAA C) and a power balance violation in the sink BAA of the IRU/RCU (BAA A or B).  Given that all of the power balance relaxation parameters are the same in the BAAs, DMM notes that it seems the small cost adder currently applied to WEIM transfers may cause the energy to stay in the IRU/RCU source BAA (BAA C) because it would be less costly to the real-time objective function to relax the power balance constraint in the sink BAA (BAA A or B) and avoid that small energy transfer cost.

For clarification of these issues, DMM requests that the ISO provide additional details of how it plans to implement the penalty prices for power balance violations and EDAM energy, IRU, and RCU in the real-time market in order to effectuate the outcomes described in the “edge case” example on pages 27-28 of the draft final proposal.

  1. EDAM resource sufficiency evaluation

Failure consequences may not provide additional incentives for each EDAM BAA to forward contract for all of its individual capacity requirements

DMM’s understanding of EDAM RSE failure consequences

In the concluding paragraph of the draft final proposal section on the EDAM RSE “Consequences of Failure”, the ISO explains when an EDAM BAA would or would not be removed from the EDAM pool for the WEIM RSE:

If the IFM can fully resolve the deficiency and cure the EDAM BAA through the market optimization, the EDAM BAA would be treated as a member of the pool of passing BAAs as the EDAM results are used in the WEIM RSE. The proposal is that if the market is unable to resolve the entire deficiency, the EDAM BAA would retain its ability to participate in the pool of passing BAAs if, by the STUC horizon ending in the hour of their shortage, the BAA can backfill the deficiency with supply.[9] (underlining emphasis added)

If an EDAM BAA fails the EDAM RSE, the BAA will still be part of the EDAM pool for WEIM RSE if the IFM “resolve(s) the deficiency and cure(s) the EDAM BAA through the market optimization.”  DMM asks that the ISO clarify exactly what it means for the IFM to resolve a deficiency and cure the BAA.  Based on this section of the proposal, it appears that the IFM will be able to resolve the failing BAA’s deficiency and cure the BAA if the EDAM BAA is able to (1) economically clear its bid-in load and (2) meet its IRU requirements in the IFM with a combination of its own supply and EDAM energy and IRU transfers from other EDAM BAAs.  In other words, a BAA that fails the EDAM RSE would remain in the EDAM pool for WEIM RSE – just as if it had passed the EDAM RSE – so long as the BAA’s IRU requirement is not relaxed in the IFM and the BAA does not have a power balance constraint violation in the IFM.

This interpretation is reinforced by the proposal’s descriptions of the out-of-market surcharge that an EDAM BAA would face if it fails the EDAM RSE and the deficiency could not be fully “cured through surplus supply offers that have been willingly bid into the EDAM.”[10]  For example, if an EDAM BAA fails the EDAM RSE, “but the market is able to meet demand, ancillary services, and (at least) 50% of the BAA’s upward imbalance reserve requirement,” that BAA’s surcharge for the amount of  the imbalance reserve requirement that had to be relaxed would remain at the Tier 2 level.[11]  If the EDAM BAA that failed the EDAM RSE ends up in the IFM market as (1) not having any of its IRU requirement relaxed and (2) does not have a power balance constraint relaxation, then under the ISO’s proposal the EDAM RSE failure deficiency will be considered to have been “cured by the market.”  In this scenario, the EDAM BAA will face no consequences – financial or being dropped from the EDAM pool for WEIM RSE – after having failed the EDAM RSE.

The rest of this section describes two ways in which this EDAM RSE design may allow an EDAM BAA to not procure sufficient capacity in advance of the day-ahead timeframe and fail the EDAM RSE, but still rely on excess capacity from other EDAM balancing areas without any consequences so long as other EDAM balancing areas have made excess supply available through their net export constraints.

One BAA’s virtual supply curing another BAA’s supply deficiency

First, we will describe a scenario involving an EDAM BAA that has more than sufficient physical supply for its own needs, but which allows virtual supply bids. Based on DMM’s understanding of the draft final proposal, such a BAA could have its reliability jeopardized in tight system conditions if it does not carefully set its net export constraint to only allow out a quantity of EDAM energy and IRU transfers that is in excess of its potential reliability needs. 

If BAAs such as this do not set their net export constraints to prevent this, another EDAM BAA that had insufficient capacity and failed the EDAM RSE could cure its deficiency via firm EDAM energy transfers in the IFM backed by virtual supply out of BAAs that had sufficient physical supply.  This can result in the EDAM BAA that passed the EDAM RSE with sufficient physical capacity having a capacity shortfall in RUC and being assigned the ultimate power balance shortfall in the real-time market.  This can also cause the entire EDAM pool for the WEIM RSE to fail the WEIM RSE. 

Before getting into an example of this scenario, we also note that in practice there are typically large quantities of virtual supply offered into the CAISO IFM at very high bid prices.  If IFM prices rise to the bid cap, virtual supply bid at or near $2,000/MWh has very little risk of loss and a high expected profit.  These virtual supply bids sell at or near $2,000/MWh in the IFM and buy back at what usually is a lower price in the FMM.

Assume there are two BAAs in EDAM (BAA 1 and BAA 2). 

  • BAA 1 allows virtual bids.  BAA 1 has a load forecast of 1,000 MW (which it self-schedules in the IFM), an IRU requirement of 100 MWs, and it has 1,100 MWs of reliable physical capacity to meet its requirements.  BAA 1 passes the EDAM RSE, and does not set its net export constraint. 
  • BAA 2 does not allow virtual bids.  BAA 2 has 800 MW of load (which it self-schedules in the IFM), an IRU requirement of 80 MWs, and 100 MWs of reliable physical capacity.  BAA 2 fails the EDAM RSE.  
  • Assume there is plenty of transfer capacity between BAA 1 and BAA 2.

DMM’s understanding of the proposed EDAM design is that in this scenario the IFM would clear as follows:

  • BAA 1’s 1,100 MWs of physical generation would meet its 1,100 MWs of load and IRU obligations.  
  • BAA 2’s 100 MWs of physical generation could meet its 80 MW IRU requirement and 20 MWs of BAA 2’s load. 
  • The remaining 780 MWs of BAA 2’s load would be served by virtual supply bids in BAA 1.  As previously noted, even in very tight system conditions, a large quantity of virtual supply bids would face very little risk of bidding at the $2,000/MWh bid cap, selling at $2,000/MWh and hoping the fifteen minute market cleared below the $2,000/MWh cap. 

In this scenario, BAA 2’s EDAM RSE deficiency has been “cured” by the IFM market.  Both balancing areas will qualify to be in the EDAM pool for the WEIM RSE.

In RUC, DMM’s understanding is that the 780 MW EDAM energy transfer from BAA 1 to BAA 2 (supported by virtual supply) would be modeled as a firm transfer out of BAA 1, increasing BAA 1’s total RUC requirement by 780 MWs.  Because the IFM energy transfers were supported by virtual supply and BAA 2 arrived to the EDAM short of capacity, there is not enough capacity to meet BAA 1’s RUC requirement.  BAA 1 will have the RUC capacity shortfall of 780 MWs even though it arrived to EDAM with sufficient physical generation to meet its load and uncertainty. 

In the real-time market, the entire EDAM pool for the WEIM RSE would be at risk of failure in a scenario such as this where virtual supply cures a deficient EDAM BAA’s capacity shortfall.  Moreover, even if no uncertainty materializes in real-time, this EDAM pool of BAAs will have insufficient physical supply to meet its total load due to the deficient BAA’s shortfall being cured by virtual supply in the IFM. 

In this example, BAA 1’s obligations in the real-time market would be 1,000 MWs of its own load plus 780 MWs of firm EDAM energy transfers to BAA 2.  BAA 2’s obligations would be 800 MWs of its own load.  DMM’s understanding from the ISO’s “confidence in transfers” section of the draft final proposal is that the optimization would utilize BAA 2’s 100 MWs of physical generation and 700 MWs of the EDAM energy transfer to satisfy BAA 2’s load.  The EDAM energy transfer from BAA 1 to BAA 2 would be reduced from 780 MWs to 700 MWs, but the 600 MW power balance relaxation would remain in BAA 1, as BAA 1 is now the area that does not have sufficient supply to meet its real-time obligations.

BAA with insufficient EDAM supply curing its deficiency by bidding its load into IFM

Based on DMM’s current understanding of the proposal, a BAA that has not procured sufficient capacity in advance of the EDAM market could also rely on excess capacity from other EDAM BAAs without EDAM RSE failure consequences by economically bidding its load into the IFM.  If a balancing area short on capacity that has failed the EDAM RSE economically bids its load into the IFM, its available capacity could serve its IRU requirements, and the amount of its load that received an IFM schedule would simply clear at a volume potentially significantly below its load forecast. 

Whether or not other EDAM BAAs had made enough capacity available to meet the short BAA’s load forecast in IFM or RUC, DMM’s understanding of the proposal is that the BAA would be deemed to have had its RSE deficiency cured by the IFM because it did not have a power balance constraint relaxation and its IRU requirement was not relaxed. If other EDAM BAAs make enough excess physical supply available in EDAM to meet the actual load forecast of the short BAA, RUC would transfer RCU from other BAAs to the BAA that was short on capacity to ensure the BAA’s reliability in real-time.  

If, on the other hand, other EDAM BAAs had not made sufficient capacity available to meet the short BAA’s load forecast, the short BAA would face a capacity shortfall in RUC.  However, this BAA would still be part of the EDAM pool for the WEIM RSE.  Moreover, it would not face any of the out-of-market financial consequences described in the draft final proposal.  Its capacity shortfall could put the entire pool at risk of failing the WEIM RSE.  However, if other EDAM BAAs ultimately make sufficient capacity available in real-time to the EDAM pool, the capacity-short BAA would face no consequences from having not procured sufficient capacity in advance of the EDAM.  

This scenario illustrates that if a BAA anticipates excess supply being made available by other EDAM BAAs, the EDAM RSE failure consequences may not create additional incentives for the BAA to procure sufficient supply in advance of the EDAM market to meet its own load and uncertainty.  Thus, while the net export constraint can protect a BAA from being exposed to reliability risks from other EDAM BAAs’ capacity shortfalls, the net export constraint does not directly prevent other BAAs from seeking to rely on EDAM rather than procuring sufficient supply in advance of the EDAM market to meet its own load and uncertainty.  As a result, DMM suggests that stakeholders may want to consider revising consequences of failing the EDAM RSE to create additional incentivizes for each BAA to procure sufficient capacity to meet its load and uncertainty before the EDAM market.

The consequences for untagged imports and other capacity that counts in the EDAM RSE but is unavailable for the real-time market should be clarified and potentially enhanced

The ISO proposes to count non-resource specific imports under “forward supply contracts” as meeting an EDAM BAA’s EDAM RSE requirements.[12]  For such imports that receive EDAM schedules, if “the EDAM BAA does not tag the outstanding [import] schedules prior to the start of the STUC run, the proposal is to remove the BAA from the pooled WEIM RSE approach.”[13]

This statement appears unclear as to whether failing to tag just 1 MW of imports by the deadline would cause the EDAM BAA to be removed from the EDAM pool for the WEIM RSE, or if perhaps all such imports would have to fail to tag.  In a subsequent section of the final draft report specifically focused on the “EDAM Entities Pooled WEIM RSE”, the proposal implies that there are no consequences for EDAM schedules ultimately becoming unavailable in real-time.  In this section, the ISO explains that “(t)he proposal is that all parties that pass the EDAM RSE would be tested as a pool in the WEIM RSE” and that “(e)ach participating BAA is expected to address any intra-day outages that render any of the capacity used to back EDAM schedules prior to the running of the WEIM RSE (sic)”.[14]

The proposal continues without listing any consequences for BAAs that fail to meet that expectation.

DMM recommends that the ISO clarify precisely what tagging failure may cause an EDAM BAA to be removed from the EDAM pooled WEIM RSE.  If an EDAM BAA passes the EDAM RSE with a significant excess of supply, removing that BAA from the EDAM pooled WEIM RSE due to 1 MW of untagged imports seems unreasonable in light of other aspects of the proposal.  For example, as previously discussed in these comments, the draft final proposal would not remove a BAA from the EDAM pooled WEIM RSE under a scenario where that BAA (1) fails the EDAM RSE, (2) has its capacity deficiency “cured” by EDAM energy transfers from another BAA, and (3) then has a large, old, unreliable gas unit that had counted towards the EDAM RSE declare itself unavailable.

DMM shares stakeholder community concerns about the potential for non-resource specific imports that EDAM BAAs count towards the EDAM RSE not actually being backed by firm generation or not being able to secure transmission.  However, other types of resources, such as VERs, gas peaking plants, and old combined cycle units can also have more of their capacity counted towards meeting the EDAM RSE requirements than ultimately is available in real-time under tight system conditions.  DMM suggests that the ISO and stakeholders consider enhancing the proposed consequences for EDAM RSE capacity that does not show up in real-time to more appropriately penalize EDAM BAAs whose uncured, underperforming capacity threatens the ability of the EDAM pool to pass the WEIM RSE.

The automated import tag verification process should be clarified and potentially enhanced

The ISO’s proposal for verifying that imports counting towards the EDAM RSE have a forward contract for firm energy is not clear.  DMM recommends that the ISO clarify its proposal and potentially enhance the verification process to ensure imports to non-CAISO EDAM BAAs have forward contracts before being counted towards meeting the EDAM RSE requirements.  DMM also recommends that the ISO potentially enhance its proposed automated e-Tag verification process prior to the final STUC run to ensure that the tagged energy for all EDAM BAA’s is non-recallable.  This section provides more detail on these recommendations.

The draft final proposal lists criteria that import bids at CAISO BAA interties must meet in order to qualify as an import with a forward supply contract that can then count towards meeting the CAISO area’s EDAM RSE requirements.  These criteria can either already be verified in an automated fashion, or the ISO proposes to “provide a means for load serving entities to link intertie bids with a forward contract”.[15]  The ISO does not seem to propose anywhere to provide a similar means for load serving entities in non-CAISO EDAM BAAs to link imports counted in the EDAM RSE with a forward contract.  DMM asks the ISO to clarify that it will be providing a means for imports of any EDAM BAA counted towards the EDAM RSE to demonstrate they have a forward contract.  DMM also asks the ISO to clarify that the ISO is proposing to automate the verification that any import has a forward contract before it can be counted towards any EDAM BAA’s EDAM RSE.

A separate but related concern is that the proposal does not describe exactly what will be verified in the proposed automated e-Tag verification process prior to the final STUC run.  The proposal describes removing the BAA from the pooled WEIM RSE approach if the EDAM BAA “does not tag the outstanding (import) schedules prior to the start of the STUC run”.[16] This seems to imply that the ISO will only be verifying that the import has tagged the requisite quantity of transmission and energy.  However, if the quality of the energy is not firm, non-recallable, the import will have failed to meet the criteria described in the draft final proposal.  Therefore, DMM recommends that the ISO’s final e-Tag verification process include verifying that the tagged energy is firm, non-recallable.  The import should then fail the verification process and contribute to whatever the consequences of failing end up being, if either the quantity or the quality of the tagged energy by the start of the STUC run does not meet the requirements.  

Implementation needs to ensure availability of requisite e-Tag data for DMM and for ISO monitoring of import tagging

The ISO explains “(t)he proposal is that the Department of Market Monitoring report monthly on the volume of day-ahead non-resource specific schedules that fail to submit valid e-tags prior to conclusion of the WEIM RSE.”  DMM will add the requested metrics to its WEIM reports, if the ISO can provide DMM with the requisite e-Tag data.  We highlight the necessity of the ISO implementation to ensure the availability of the appropriate e-Tag data for this kind of reporting because DMM has put some effort into shaping into a usable format the e-Tag data currently available to DMM in CAISO databases.  DMM appears to only currently have database access to e-Tag data for transactions that touch the CAISO balancing area.  DMM requests the ISO provide, in databases that DMM can access, the requisite e-Tag data for all imports and exports for all EDAM and WEIM BAAs.

  1. Greenhouse gas accounting and reporting

The resource specific GHG accounting proposal is reasonable, but DMM recommends the ISO consider the LADWP approach as a future enhancement

DMM supports the ISO’s proposed resource specific approach to greenhouse gas (GHG) accounting.  It strikes a reasonable balance between (a) minimizing total production costs by ignoring secondary dispatch and (b) preventing a low cost dispatch with constraints that attempt to eliminate secondary dispatch.  However, DMM continues to recommend that the ISO consider LADWP’s proposed variation of the resource specific approach as a future enhancement.  The rest of this section provides clarification of these points.

The ISO’s GHG accounting proposal is reasonable

The market software’s primary objective is to minimize the total dispatch cost, subject to GHG zone regulators’ accounting constraint of determining the GHG emissions caused by EDAM imports into each GHG zone.  The original EIM GHG accounting design optimally accomplished the primary objective of minimizing the total dispatch cost by deeming the dispatches from resources with the lowest emissions outside of a GHG area as the resources that the GHG area would choose to import. This formulation ignores the fact that if the optimization is importing zero emissions resources from non-GHG areas such as solar into a GHG area to displace emitting resources such as natural gas, the non-GHG area may be backfilling the solar it sold with even higher emitting resources such as coal.  This “secondary dispatch” of the high emitting coal to ultimately displace the lower emitting natural gas can occur because the optimization does not consider the emissions costs of power produced and consumed in a non-GHG area.

Most of the controversial aspects of the ISO’s GHG design involve constraints on the original GHG accounting formulation that limit what the optimization can deem delivered to GHG areas in order to reduce the potential for the optimization to dispatch up higher emitting resources in a non-GHG area that ultimately displace lower emitting resources in a GHG area.  None of the additional constraints considered eliminate secondary dispatch.  Each of the constraints that has been considered to try to limit secondary dispatch has a significant drawback that has to be weighed against the extent it may help to limit secondary dispatch.

Some stakeholders have argued to limit the power that can be deemed delivered from each resource to a GHG area to the resource’s incremental production between the counterfactual GHG market run and the binding market run.  DMM does not support this stakeholder proposal due to the inconsistencies it creates between resource’s prices and costs, as the ISO has explained in its draft final proposal and the stakeholder meeting for that proposal.[17]

The ISO has proposed a GHG net export constraint to limit the GHG attributions in a non-GHG balancing area to the increase in the BAA’s net exports between the counterfactual GHG run and the binding market run.  DMM appreciates the analysis the ISO has done to help assess the tradeoff between the extent to which this constraint limits transfers to GHG areas and its potential to reduce secondary dispatch.  Based on the ISO’s analysis, the proposed GHG net export constraint does not seem to overly constrain the availability of GHG bids.  The constraint may be a reasonable feature to help limit secondary dispatch.

DMM supports the ISO’s GHG accounting proposal overall as a reasonable compromise between features that help to reduce secondary dispatch without escalating total dispatch costs by overly limiting the bid set that can be deemed delivered to GHG areas.

DMM recommends considering LADWP approach as future enhancement

DMM continues to recommend that the ISO consider a resource specific GHG accounting approach similar to the model proposed by LADWP.[18] The proposal would eliminate the need for resources outside of a GHG area to interact with other states’ regulators and ensures GHG congestion rents are being allocated to the entities paying for emissions allowances. The LADWP proposal is flexible to accommodate additional state-run cap-and-trade programs while maintaining the benefits of a resource-specific optimization.

DMM continues to believe that the ISO should maintain flexibility in its GHG design so that it can be adapted to best suit the specific regulations of each unique GHG program. While the ISO’s proposed constraints on non-GHG area dispatch that can be deemed delivered to a GHG area aim to address secondary dispatch, it is possible that the state regulator may not fully incorporate or reflect the ISO market’s GHG attributions in their GHG program design. For example, CARB’s regulations currently collect allowances for all WEIM MWh deemed delivered to California at the unspecified emissions rate, regardless of what resources the market deems as delivered.[19] While emitting resources outside of California who are deemed delivered are responsible for the share of allowances associated with their specific emission rates, California utility distribution companies (UDCs) are responsible for all remaining EDAM/WEIM emissions allowances.

LADWP’s approach proposes that the state’s UDCs be responsible for all their state’s EDAM/WEIM emissions, instead of collecting allowances from resources outside the state. Because UDCs would be responsible for the GHG compliance costs of all EDAM/WEIM emissions, these entities would receive the GHG rents. There are a number of benefits to this design. First, resources outside of GHG areas will not need to interact with other states’ regulators. In addition, the LADWP approach ensures that GHG rents are allocated to the entities paying for the emissions allowances. This protects UDCs if their state’s GHG program, similar to California’s CARB program, does not incorporate the ISO market’s GHG attribution outcomes into their regulations. For example, when a hydro resource is deemed delivered to California in the WEIM, the California UDCs will need to retire allowances for those MWh at the unspecified emissions rate while the GHG rents will be allocated to the hydro resource. Under LADWP’s proposal, the California UDCs will still need to retire emissions allowances for those MWh, but the UDCs will also be receiving the GHG rents.

The GHG counterfactual market run is aimed to address secondary dispatch and may allow for more flexibility in how state regulators design GHG programs. States could choose an approach like CARB or base the number of emissions allowances on the ISO market’s GHG attribution outcomes. Concerns have been raised about the incentive/ability for resources to game the GHG reference pass in order to create headroom and be deemed delivered in a later market run. Another benefit of the LADWP proposal is that allocating GHG rents to UDCs, rather than resources, would mitigate these gaming concerns.

As suggested by LAWDP, this model would be better constructed with an opt-out approach for resources versus opt-in. Resources that did not opt-out would have a GHG bid adder inserted by the ISO. A potential drawback of this proposal is whether resources will have enough incentive not to opt-out if they are not receiving the GHG congestion rents. Although it is likely that the opportunity to be delivered to a GHG area and receive inframarginal rents on energy will be incentive enough, if many resources choose to opt-out this will affect the supply of GHG bids.

The LADWP approach, as a relatively straightforward variation of the ISO’s current resource-specific approach, allows the optimization to use resource-specific inputs and protects non-GHG areas from being exposed to higher prices due to the GHG compliance costs. However, under the LADWP approach, state regulators collect compliance costs associated with EDAM/WEIM emissions entirely from their state’s UDCs, rather than having resources outside the state interact with the regulators. This makes the EDAM more flexible to accommodate additional cap-and-trade programs down the road.

  1. Transfer revenue and congestion revenue allocation

The ISO’s proposed transfer and congestion revenue allocation appears to be an improvement over the existing approach for the WEIM

The EDAM draft final proposal appears to retain some elements of the existing WEIM transfer and congestion revenue allocation, including a 50/50 split of transfer revenue in some circumstances, and 100 percent allocation of congestion revenue from ITCs and internal constraints to the BAA where the constraint is modeled.  However, the EDAM proposal makes the following key changes:

  1. The ISO proposes to create a marginal energy component (MEC) of LMP specific to each BAA.  DMM understands that this BAA-specific MEC will reflect the shadow price of each BAA’s power balance constraint, and will replace the current approach for WEIM that uses a system marginal energy component and includes the BAA specific power balance shadow prices in the marginal congestion component of LMP.  The ISO then proposes to calculate the transfer revenue based upon the difference of each BAA’s energy component of LMP.

 

  1. The ISO proposes to generally allocate transfer revenues across all EDAM BAA interfaces in a 50:50 split, subject to certain commercial arrangements that may require exception.  This appears to be a departure from the existing WEIM framework which allocates 100 percent of transfer revenues to an entity that brings transmission rights “to” but not “through” an interface with another BAA.

 

  1. The ISO proposes to allocate 100 percent of transfer revenue associated with Bucket 2, Pathway 2 transmission released to EDAM in advance of the market run to the transmission customer releasing those transmission rights.

DMM does not oppose the ISO’s proposal to establish a marginal energy component of LMP for each BAA rather than using the system marginal energy component and including BAA specific shadow prices in the congestion component of LMP.  DMM requests that the ISO publish a mathematical formulation for the proposed approach, clearly specifying the formulation of each BAA’s power balance constraint, transfer constraints, and how the respective shadow prices enter the formulation of LMP for each BAA.

The ISO’s proposal to allocate most transfer revenues in a 50/50 split may be an improvement over the existing WEIM approach to transfer revenue allocation.  Allocating transfer revenue in a 50/50 split reduces incentives for any entity to withhold capacity in order to increase transfer revenues. However, the ISO’s proposal still allows 100 percent of transfer revenue to the entity bringing the transmission rights in some circumstances. Any proposal where 100 percent of transfer revenue is allocated to an entity making transmission available to EDAM for transfers may create incentivizes to withhold transmission in order to cause transfer constraints to bind and maximize transmission revenues.

These incentives are unique to the EDAM and WEIM market designs where transmission is required to facilitate transfers, but is provided voluntarily by market participants. This is a distinctly different concept from a standard ISO/RTO framework where all available transmission is routinely made available to the market, without concern for other commercial decisions.  However, when an EDAM and WEIM transfer constraint binds, generators in the area on the exporting side of the binding constraint realize lower prices.  In the WEIM, the entities providing transmission for WEIM transfers are typically affiliates of the majority of generation within the BAA.  Therefore, any additional transfer revenues realized by withholding transmission would be largely offset by lower prices realized by affiliated generators. 

DMM believes this outcome largely mitigates incentives to withhold transmission in the WEIM context, and may continue to do so in EDAM.  However, this potential mitigation in EDAM is not guaranteed, and the EDAM design should carefully consider what incentives it creates for entities to provide transmission to, or withhold transmission from, the market. This includes careful consideration of the congestion rent allocation framework.

The ISO’s proposal would also continue to allow BAAs modeling ITCs to retain all congestion revenues associated with the ITC.  DMM notes that although all congestion revenues are retained by the entity modeling the ITC, in the case of the CAISO, ITC limits are determined by well-documented and defined operating procedures.  As such, this ITC capacity is not subject to the same withholding incentives as some other EDAM or WEIM transfer capacity, and is not determined arbitrarily on a day-to-day basis dependent on commercial considerations.

The proposed allocation of transfer revenue appears to create new avenues for monetization of transmission rights

DMM notes that the ability of a BAA (e.g., CAISO) to retain congestion revenues associated with an ITC within the BAA is not a new concept with the proposal of EDAM.  It has long been the case that entities can offer day-ahead import bids at CAISO interties without first securing upstream transmission, and that these import bids can lead to congestion revenues which are retained by the CAISO BAA.  DMM understands that the transmission rights upstream of CAISO BAA interties have historically been monetized by means other than congestion revenues associated with CAISO ITCs.  Therefore, while the ISO proposes to continue allowing the CAISO BAA and any other BAA modeling ITCs to fully retain the associated congestion revenues, the proposed EDAM design actually appears to create new avenues for monetization of transmission rights upstream of CAISO interties when these rights are offered to EDAM and become eligible to receive transfer revenues.

DMM requests clarification of some transfer revenue allocation scenarios

The ISO proposes a 50/50 split of transfer revenues for EDAM transfers, as well as an option for entities to retain 100 percent of transfer revenues on Bucket 2, Pathway 2 transmission made available to the EDAM in advance of the market run. DMM requests additional clarification of how the ISO plans to implement the allocation of 100 percent of transfer revenues where proposed. 

Consider a case where an entity in BAA 1 brings Bucket 2 transmission to EDAM in advance of the market run to facilitate EDAM transfers with BAA 2.  There is additional Bucket 3 transmission made available in BAA 1.  All transmission made available for EDAM transfers in BAA 2 is Bucket 3 transmission.

In this scenario, would the total transfer revenues be allocated 50/50 among the BAAs, with the entity offering Bucket 2 transmission in BAA 1 retaining 100 percent of their MW proportionate share of total transfer revenues allocated to that BAA?  Similarly, how would the transfer revenue allocation occur if EDAM transmission in both BAA 1 and BAA 2 were exclusively Bucket 2 transmission made available before the start of the EDAM market?  DMM requests that the ISO provide examples to clarify the proposed allocation of transfer revenues in these and other potential scenarios.

 

 

 


[1] Extended Day-ahead Market – Draft Final Proposal, California ISO, October 31, 2022: http://www.caiso.com/InitiativeDocuments/DraftFinalProposal-ExtendedDay-AheadMarket.pdf

[2] For example see Comments on Day-Ahead Market Enhancements: Third Revised Straw Proposal, Department of Market Monitoring, May 19, 2022, pp. 5-6: http://www.caiso.com/Documents/DMM-Comments-Day-Ahead-Market-Enhancements-3rd-Revised-Straw-Proposal-May-20-2022.pdf

[3] For example see Comments on Day-Ahead Market Enhancements: Third Revised Straw Proposal, Department of Market Monitoring, May 19, 2022, pp. 5-6: http://www.caiso.com/Documents/DMM-Comments-Day-Ahead-Market-Enhancements-3rd-Revised-Straw-Proposal-May-20-2022.pdf

[4] DMM appreciates that the ISO has proposed a configurable diversity benefit parameter to potentially reduce the probability of EDAM footprint capacity shortfalls below 2.5%.  However, in the absence of more detailed descriptions of how this parameter will be set to ensure capacity levels are sufficient to meet standard reliability criteria such as loss of load in no more than 1 day every 10 years, it does not seem reasonable for a balancing area to let its own reliability rely on how the Market Operator sets this parameter.

[5] ISO’s October 31 EDAM Draft Final Proposal, p. 76.

[6] ISO’s October 31 EDAM Draft Final Proposal, p. 22.

[7] Ibid, pp. 27-28.

[8] Note that this is the same example as the final example from section II.2.(b) of the Draft Final Proposal.  We reference these slides because the draft final proposal does not seem to list the revised WEIM power balance constraints. EDAM Revised Straw Proposal-Stakeholder Meeting presentation, CAISO, September 7, Slide 70: http://www.caiso.com/InitiativeDocuments/Presentation-ExtendedDay-AheadMarket-Sep7-8-2022.pdf

[9] ISO’s October 31 EDAM Draft Final Proposal, p. 70.

[10] Ibid, p. 67.

[11] Ibid, p. 68.

[12] ISO’s October 31 EDAM Draft Final Proposal, p. 64.

[13] ISO’s October 31 EDAM Draft Final Proposal, p. 65.

[14] ISO’s October 31 EDAM Draft Final Proposal, p. 72.

[15] ISO’s October 31 EDAM Draft Final Proposal, p. 65.

[16] Ibid.

[17] ISO’s October 31 EDAM Draft Final Proposal, p. 101.

[18] Comments on Extended Day-Ahead Market Straw Proposal, Department of Market Monitoring, June 17, 2022: http://www.caiso.com/Documents/DMM-Comments-Extended-Day-Ahead-Market-Straw-Proposal-June-17-2022.pdf

[19] CARB Electricity Sector Greenhouse Gas Accounting Presentation, slide 9: http://www.caiso.com/InitiativeDocuments/CARBPresentation-ElectricitySectorGreenhouseGasAccounting-EDAMWorkingGroup%203-Feb152022.pdf

 

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

For a fully formatted version of DMM's complete set of comments, please the pdf attached below the ISO's final question below.

California Public Utilities Commission - Energy Division
Submitted 11/30/2022, 03:19 pm

Contact

Michele Kito (MK1@cpuc.ca.gov)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

CPUC Energy Division Staff (hereinafter “Staff”) appreciates the opportunity to comment on the CAISO’s Extended Day-Ahead Market draft final proposal.  Staff appreciates many of the changes made throughout this and the related Day-Ahead Market Enhancements stakeholder processes, including 1) the recent addition of the net export constraint, 2) the return of Imbalance Reserve/Residual Unit Commitment payments, 3) the retention of the real-time must offer requirement for resource adequacy resources, 4) the ability of the CAISO BAA to utilize its RDRR resources if it appears that it might fail the resource sufficiency evaluation (RSE), 5) the ability of the CAISO BAA customers to use non-resource specific imports to meet the EDAM RSE, among other changes. 

Staff also have several questions and concerns about the overall benefits and costs associated with EDAM, as well as specific concerns regarding the application of the RSE and the EDAM construct and its effect on reliability for CAISO’s California customers.  Staff continues to have questions regarding EDAM’s impacts on costs and reliability for California customers over the current status quo and seeks assurance that it will not result in any unintended consequences in terms of reliability and costs – cornerstones of the CPUC’s mandate to ensure just and reasonable rates for its customers.

Some of Staff’s concerns and questions are summarized below and some are discussed in greater detail in response to individual questions below.

Benefits and costs

Based on analysis of the potential benefits associated with EDAM provided in the draft final proposal, Staff is concerned that the benefits are relatively small compared to the unknown costs and potential reliability issues that could arise as a result of EDAM and the associated stakeholder processes, including the day-ahead market enhancements (DAME) and CAISO’s price formation initiative. For example, in its draft final proposal, CAISO estimated “the economic benefits of a day-ahead market across the Western Interconnection are estimated to range between $95 and $400 million annually, in addition to those seen in the WEIM.” Assuming that CAISO customers receive 15% or 20% of these potential EDAM benefits (based on the EIM benefits received in 2022 and EIM benefits received since the inception of the EIM), the expected CAISO BAA’s EDAM benefits would range from ~$14 million to ~$80 million annually. 

On the other hand, costs could increase for a range of reasons, that remain to-date largely unquantified, including 1) costs associated with the new imbalance reserve and reliability capacity products, which were previously available at no cost via the RA must-offer obligation in the residual unit commitment process, with zero dollar bids and return of largely all RUC capacity compensation to CAISO’s California customers, 2) costs associated with any penalties to be imposed as a result of the EDAM RSE failure, which do not exist in the current day ahead market construct, 3) costs associated with scarcity pricing or fast-start pricing that some EIM entities are insisting is a precondition to their joining the EDAM, and which PowerEx estimates could rise to $500 million in additional costs to CAISO’s California customers, 4) costs associated EDAM implementation and on-going administration, given that all other EDAM entities can exit with a six month notice with no exit fees, and 5) potential costs associated with new transmission tagging requirements for non-resource specific imports that are critical  to California’s reliability and do not currently require e-tagging in the day-ahead or STUC timeframe.

While Staff understands that Energy Strategies has updated the estimate of benefits, it is not clear that this analysis took into account the potential costs associated with EDAM, enumerated above. Further, since this analysis came out so late in this process, Staff has not had sufficient time to understand and vet the updated benefits. Staff believes that a rushed schedule creates a risk of getting the design wrong, and seems unnecessary.

With regard to costs, Staff understands that CAISO’s position is that the imbalance reserve product will be returned to CAISO’s California customers through reduced capacity prices in the future, but Staff is concerned that this would not be the case for the many long-term contracts that have been or are being signed to meet CPUC mandates for additional resources on the grid.  Further, CAISO has raised the prospect that existing RA contracts contain clauses for return of capacity payments, but whether this will be the case will turn on whether generators agree that these provisions are applicable to newly created products, like imbalance reserves, and this could result in litigation and uncertainty for a considerable period of time. To help assess potential costs, Staff requests that CAISO release an estimate of the costs associated with the new imbalance reserve product, and also estimate the potential costs associated with its newly proposed EDAM RSE penalty parameters had those penalty parameters been in place during September 2022. This could establish an upper bound of potential penalty costs associated with EDAM RSE failure in the future (e.g., associated with 1-in-20 or similar weather events, for which CAISO does not currently impose penalties).  This would allow stakeholders to review the estimates and provide comments on whether and to what extent there may need to be changes to how the imbalance reserve product functions,

Reliability Concerns

In terms of reliability, Staff is primarily concerned that CAISO currently has the ability to recall all low priority exports up to and beyond the hour-ahead scheduling process, and this capability is largely what allowed CAISO to serve load during the transmission outage on July 9, 2021 (by cutting these exports in the HASP process), but with EDAM it will lose the flexibility as to the recalling low priority exports should those exports be considered transfers, that CAISO will now prioritize equal to load, even if they are facilitated by intertie bids that do not flow due to a similar outage. 

In this regard, CAISO has clarified in numerous stakeholder processes that any required cuts under these circumstances would be pro rata, which means that if CAISO is supporting transfers of 2,000 MW (based on 2,000 MW economic imports at its ties) and a transmission line goes down that results in a 2,000 MW infeasibility,  then assuming a CAISO load of 45,000 MW  then 85 MW of transfers would be cut and 1,915 MW of load would be cut, meaning that the cuts (and loss of load) would primarily be borne by CAISO’s California’s customers.  This therefore represents a shift from the current practice of cutting low priority exports when they are not supported, with the resulting “shared pain” of the cuts borne almost entirely by CAISO load – this represents a reversal of the treatment of low priority exports from current practice under these circumstances.

Regarding reliability, Staff understands that CAISO’s position is that the imbalance reserve and reliability capacity products, as well as the net export constraint, will sufficiently protect CAISO’s California customers, but Staff is concerned that this protection hinges on the specification and implementation of these products. In this regard, Staff notes that based on CAISO’s analysis, the imbalance reserve product will not sufficiently cover the load conformance adjustments that CAISO currently makes in the RUC process during high load periods to ensure adequate protection of California’s load (see figure below). This figure demonstrates that the imbalance reserves cover less than 100 percent of the RUC adjustments during high forecast periods and in many cases, the imbalance reserve product covers 50% or less of the RUC adjustments that CAISO operators are making in the RUC process.  

 

image-20221130144215-1.png

In addition, Staff also notes that the specification of the imbalance reserve product will use a quantile regression process, which has not yet been implemented for the flexible ramping product due in part to its complexity, and, thus, does not yet have a proven track record to accurately estimate the uncertainty in the real-time, or the longer day-ahead timeframe. Staff has three additional concerns regarding the imbalance reserve product.  First, there is no RA must-offer for the imbalance reserve product, thus leading to potential market power concerns.  Second, imports into the CAISO BAA are not typically 15 minute dispatchable, further limiting the pool of resources to meet the imbalance reserve requirement for the CAISO BAA, given that CAISO relies on imports to a greater extent than other BAAs.  Third, Staff notes that CAISO removed the net load uncertainty in the existing EIM RSE test because it resulted in spurious failures and is now waiting for implementation of a new FRP quantile regression methodology and has proposed deferring implementation in the RSE until CAISO can assess how the FRP is working, but here CAISO is proposing the same methodology that has not yet been fully implemented and evaluated in the real-time market.

Finally, Staff appreciates that CAISO did, in its ”Draft Final” iteration of its proposal, introduce a net export constraint that is primarily intended to address (1) the CAISO BAA issue having to do with the must-offer for all of its resources that can get committed to serve other BAAs and (2) the fact that the CAISO BAA alone allows intertie bidding, which can also support “transfers” to other EDAM BAAs in the CAISO’s day-ahead optimization.

While the net export constraint can work to prevent CAISO’s California customers from supporting transfers to other EDAM BAAs using its own RA resources or using intertie bids, this new net export constraint will only work if it is used.  Staff is concerned that CAISO has indicated that if it is used, it would reduce the efficiency of the day-ahead market and that, based on CAISO’s experience, import bids appear reliable and, thus, CAISO has indicated it would make sense to not set the parameter for net exports of intertie resources to zero. First, Staff notes that other BAAs have made clear that they do not want CAISO to use this parameter (thus putting CAISO in the position of supporting transfers equal to load), at the same time that other BAAs express the desire to only commit resources necessary to pass the RSE (thus limiting those transfers which other BAAs will prioritize equal to load). Second, CAISO has not indicated how this parameter will be set, how often it will change, what role the CPUC and load serving entities in the CAISO have in setting this parameter, and how setting this parameter will ensure that RA resources are protected and CAISO load is not put at risk of supporting transfers that are effectuated by import bids that can fail to materialize for a variety of reasons, including transmission outages (similar to what occurred on July 9, 2021).

At this point, absent further information, Staff supports setting this parameter to zero in the day-ahead timeframe and releasing the CAISO RA resources and import bids at the ties to support transfers, only in the real-time timeframe, given the substantial uncertainties that can arise between the day-ahead and real-time timeframes or setting it such that CAISO has a buffer of internal generating resources, similar to that effectuated through the RUC process and similar to methods used by other BAAs in reserving available balancing capacity or holding back resources that are not being used to meet their RSE tests. In the alternate, if CAISO could come up with a means to ensure that the CAISO BAA is not required to support transfers based on intertie bids that do not materialize and, as a result, adversely impact CAISO’s California customers’ reliability, Staff would support such a mechanism.  In addition, Staff believes if the intertie bids are firm enough to support EDAM transfers, they should be firm enough to count towards CAISO’s resource sufficiency test in the first place.

On a separate, but related note, in the stakeholder process, Staff asked CAISO whether it would set the net export limit to zero if the CAISO failed the RSE, but CAISO indicated that transfers would continue, explaining that it would not bind in conditions where an EDAM BAA failed the RSE because CAISO would need the imports.  However, imagine that the RSE requirement during stressed system conditions was 48,000 MW, and CAISO had 47,000 MW of resources and thus failed the RSE.  At the same time, if there were import bids of 3,000 MW or virtual bids of 3,000 MW, could these support transfers out of the CAISO system?  And under what conditions and how? Would this not compound the potential reliability risk to California customers under these potentially stressed system conditions?  In addition, does CAISO have any ability to take back cleared transfers in the RUC process, as it can do today – why or why not?

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

In this section, CAISO proposes a voluntary participation model, with “voluntary entry and exit with a six-month notice period and no exit fees.”  In addition, CAISO proposes “transitional protection measures that limit and mitigate adverse reliability and market outcomes resulting from EDAM participation, particularly during the initial stages of market implementation and the onboarding of individual EDAM entities.” Staff does not oppose CAISO’s proposals, but has several questions and clarifications.

  • Given that non-CAISO entities are able to voluntarily enter and exit, without exit fees, Staff notes that any costs associated with EDAM start-up and continued operation would appear to remain with CAISO’s California customers Therefore, in order for Staff and parties to accurately assess the potential costs of EDAM, could CAISO provide an estimate of the start-up costs associated with EDAM and its annual estimate of the costs associated with EDAM operation? It would also be helpful if CAISO could identify which costs are incremental and which are not, given its current cost structure.
  • CAISO states that “[e]ase of entry and exit are key design concepts that allow an EDAM entity to evaluate the impacts and benefits of participation and enable the entity to cease participation if those impacts and benefits do not meet expectations.”  Can CAISO clarify whether the CAISO BAA is afforded this same optionality, to enter and exit with six months notice, with no exit fees in the event that CAISO BAA determines that the benefits do not outweigh the costs? And if this is the case, who would pay for the EDAM start-up and on-going cost of operation?
  • CAISO states that the transitional measures apply to CAISO as well as EDAM entities.  Can CAISO clarify that its BAA will have the ability afforded to other EDAM entities to: 1) change its implementation date, 2) temporarily suspend EDAM participation, 3) be subject to transitional pricing mechanisms, and 4) interrupt participation in the EDAM market, should reliability or other issues arise?
3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

In Section II.A.2, CAISO describes an example of what the EDAM would expect from EDAM entities in stressed conditions. Note that this example is discussed in different ways throughout this section (emphasis added):

In more stressed system conditions, where the market has exhausted all of its tools but the reliability conditions cannot be fully resolved, the EDAM entity may need to rely on its operational tools to manage grid reliability and respond to the reliability event. Each EDAM entity retains its BAA reliability function. In these conditions, the BAA can rely on its individual operational tools to resolve the reliability event. If exercising such reliability tools does not resolve the reliability event and the risk of load shed remains, the EDAM BAA would afford market transfers and load equal priority subject to operational discretion and coordination, consistent with good utility practice. This means that load and transfers will be curtailed on a pro-rata, basis.

Please see Staff’s comments regarding reliability, CAISO’s proposal to prioritize transfers equal to load and, in stressed system conditions, cut pro rata, and a discussion of the net export constraint, in response to Question 1, above. 

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

 No comments at this time.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

 No comments at this time.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

 No comments at this time.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

Below are Staff comments, questions, and requests for clarification on a number of items contained in CAISO’s proposal EDAM resource sufficiency evaluation.

Preliminary RSE runs.  The purpose of the preliminary RSE runs is to allow a BAA to cure its deficiency. It would be helpful for CAISO to clarify how it intends to allow this curing to occur for the CAISO BAA, given the numerous load serving entities in its footprint that presumably will have contributed different proportions of resources to the preliminary RSE run relative to their proportion of CAISO load.

Treatment of intertie bids. Staff appreciates CAISO proposal to allow non-resource specific imports to count towards the EDAM RSE. However, as requested by numerous EIM entities, many of whom own significant quantities of transmission to the CAISO border, CAISO proposes to require that non-resource specific supply to be e-tagged within three hours of the ISO publishing day-ahead market results or, in the alternate, the by the start of the short-term unit commitment horizon.  First, Staff is concerned that this requirement could raise costs for CAISO’s California customers, given that this is not a requirement under the current construct, and RA imports have performed well under stressed system conditions over the last two summers without this requirement.  Second, Staff is concerned that this requirement could also lead to the higher costs resulting from the potential of the exercise of transmission market power, or failure of the RSE, if entities release their transmission to the EDAM but it cannot be used to support non-resource specific imports. 

It would also be important for CAISO to clarify whether all imports need to have firm e-tags, or only those that are or were necessary to pass the RSE.  For example, assume that the CAISO BAA has an RSE requirement of 45,000 MW and has 45,000 MW of resources, and 3,000 MW of non-resource specific imports.  Even though the CAISO BAA passes the RSE without the non-resource specific imports, must these non-resource specific imports e-tag by the STUC horizon?  And, if they are not needed and fail to tag, does the CAISO BAA fail the RSE and, if so, why would that be the case?  This issue arises in particular because the CAISO has a must-offer for all of its resource adequacy resources – a requirement not applicable to all other BAAs, so CAISO’s clarification regarding this requirement would be particularly important.  Further, if an e-tag is not required for imports that are not necessary to pass the RSE for the CAISO BAA, how would this information be communicated to the load-serving entities?

Treatment of reliability demand response resources.  CPUC jurisdictional entities have approximately 800 MW of base interruptible program (BIP) resources that the CPUC has indicated can be used at a warning stage, which CAISO has defined as an EEA 2. Staff and other parties have requested that CAISO include these RDRR resources in the EDAM RSE test, if the CAISO BAA is expected to fail the RSE. In the draft final proposal, CAISO states that, “[I]f advisory EDAM RSE results indicate a potential inability for the ISO BAA to meet its next day obligations, the ISO could modify its forecast in the extended day-ahead market and the RUC.” (Emphasis added.) Staff request clarification that CAISO would affirmatively use the RDRR resources to meet the EDAM RSE test, rather than merely stating that it could do so, given that the purpose of the RDRR resources is to meet resource adequacy needs in stressed system conditions, precisely those in which CAISO is expected to fail the day-ahead RSE and incur substantially penalties as a result. Absent such assurance, Staff is concerned that this could result in double (and potentially triple) payments for this capacity – first to the RDRR provider, second for the penalties for the EDAM RSE failure, and third for the replacement resource(s) through the market optimization, if RDRR is not considered in the day-ahead timeframe.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

Staff has several questions and concerns about CAISO’s proposal to impose penalties for failure to meet the resource sufficiency test in the day-ahead timeframe. 

First, Staff notes that this is a new requirement that does not exist in the current construct and that it will raise costs for CAISO’s California customers, who currently do not have a day-ahead resource sufficiency test and can use the intertie bids to meet load during stressed system conditions or for economic displacement, without first having to pay a penalty. Second, the proposed penalties are tied to bilaterally traded hubs, however, these hubs are exceptionally thinly traded during stressed system conditions (e.g., 3 trades at Palo Verde on one day, and only 4 on several other days during the September events). This makes these hubs not suitable for establishing penalty prices and potentially subject to manipulation if it takes just one trade on the index to establish potential penalty prices for the CAISO and other BAAs during stressed system conditions.  Third, it would be helpful for CAISO to clarify whether the CAISO BAA fails the RSE if it fails to tag any non-resource specific imports and how this would be captured in the proposed penalty proposal.  Using the example discussed in Question 7, above, if the CAISO had 45,000 MW of load and 45,000 MW of resources and 3,000 MW of non-resource specific imports and 2,000 MW failed to submit e-tags by the STUC horizon, what penalty would apply? No penalty because the CAISO BAA is in fact resource sufficient or 2,000 MW because the CAISO BAA failed to submit valid e-tags for its non-resource specific imports?

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

No comments at this time.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

Please see Staff’s comments regarding reliability, CAISO’s proposal to prioritize transfers equal to load and, in stressed system conditions, cut pro rata, and a discussion of the net export constraint, in response to Question 1, above. 

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

Please see Staff’s comments in response to Question 1 above.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

Staff has several questions about the IFM and RUC process.  One of the issues that arose in August 2020 was that the IFM cleared exports based on virtual supply, despite the fact that the solution was not physically feasible. In this regard, will it be possible under the proposed construct for the IFM to clear EDAM transfers based on virtual supply?  One way CAISO addressed this issue under the current construct, was to use a high load forecast in the RUC process and, as a result, curtail export bids in RUC.  However, the newly proposed imbalance reserve product does not cover the RUC adjustments and, as a result, Staff wonders whether this will result in problems similar to those that occurred in August 2020, and if not, why not?  Further, it would be helpful if CAISO could clarify whether these transfers could be cut in the RUC process, similar to the way in which exports can be cut in the RUC process, or whether the only mechanisms for ensuring that potentially infeasible transfers do not materialize is through the imbalance reserve and/or the net export constraint process (and how this would work).

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

 No comments at this time.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

No comments at this time.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

 No comments at this time.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

 No comments at this time.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

 No comments at this time.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

 No comments at this time.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

 No comments at this time.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

 No comments at this time.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

 No comments at this time.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

Similar to comments made in response to Question 2 above, in order for Staff and other parties to accurately assess the potential costs of EDAM, it would be helpful if CAISO could provide an estimate of the start-up costs associated with EDAM and its annual estimate of the costs associated with EDAM operation. It would also be helpful if CAISO could identify which costs are incremental and which are not, given its current cost structure. In particular, does CAISO have an estimate of the costs associated with updates to its computer algorithms and additional staff necessary to undertake the proposed EDAM and other associated initiatives?

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

No further comments at this time.

CPUC - Cal Advocates
Submitted 11/22/2022, 04:27 pm

Contact

Edmond Yi (edmond.yi@cpuc.ca.gov)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) is an independent consumer advocate with a mandate to obtain the lowest possible rates for utility services, consistent with reliable and safe service levels, and the state’s environmental goals.[1]

 


[1] Pub. Util. Code Section 309.5

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

 Cal Advocates does not have comments on this section at this time.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

 Cal Advocates does not have comments on this section at this time.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

 Cal Advocates does not have comments on this section at this time.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

 Cal Advocates does not have comments on this section at this time.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

The California Independent System Operator (CAISO) proposes the requirement of firm point to point transmission service for resources to qualify for “Bucket 1” transmission and support the Resource Sufficiency Evaluation (RSE).[1]  In the CAISO Resources Adequacy (RA) Enhancements Initiative, the CAISO similarly proposed the requirement of firm transmission on the last leg of interest to the CAISO.[2]  Cal Advocates and the CAISO Department of Market Monitoring (DMM)[3],[4] both noted in the RA Enhancements Initiative that this requirement would create concerns regarding the exercise of transmission market power.  Cal Advocates’ independent analysis found potentially noncompetitive conditions at the California-Oregon Border (COB) and Nevada-Oregon Border (NOB) interties, with the NOB meeting the definition for a highly competitive market.[5]

Despite this potential risk of transmission market power under firm transmission reservation requirements for resource adequacy, the CAISO has not provided any plan to monitor for or mitigate the exercise of transmission market power in the EDAM.  Exercise of transmission market power may present opportunities for holders of significant long-term transmission rights to withhold transmission and maximize profits for sales of transmission capacity at the expense of ratepayers in California and other EDAM-participating balancing area authorities (BAAs). To address this risk, Cal Advocates recommends that the CAISO determine a test to evaluate the potential for, and to monitor the exercise of transmission market power in the EDAM.  Cal Advocates also requests further discussion of market design options to mitigate the potential for transmission market power, such as an appropriately timed release of Bucket 1-eligible transmission to the EDAM for an at-cost compensation to the Transmission Owner to safeguard against the withholding of transmission capacity.  The CAISO should also publicly report on any market power mitigation measures taken as the CAISO monitors for transmission market power and takes the necessary actions to protect market integrity of the EDAM. 

Additionally, Cal Advocates is concerned with the potential of overcollection of transfer revenues by transmission rights holders using the Bucket 2 Pathway 2, which is described in the EDAM Draft Proposal.[6]   Cal Advocates recommends that CAISO consider the potential for a transmission rights holder to initially withhold transmission rights from the EDAM, and purposefully release transmission rights using Pathway 2 during times of congestion at an intertie to the CAISO border to drive up the spread of transfer revenue between BAAs.  The transmission rights holder might then collect increased transfer revenue between BAAs without optimally contributing transmission capacity for use in the EDAM.  Failing to address this problem may result in an unfair allocation of transfer revenue to the transmission rights holder at the cost of ratepayers in both CAISO and other EDAM-participating BAAs. 

 


[1] CAISO.  Extended Day-Ahead Market Draft Final Proposal.  p.35.  Accessible at DraftFinalProposal-ExtendedDay-AheadMarket.pdf (caiso.com).

[2] CAISO.  Resource Adequacy Enhancements Draft Final Proposal – Phase 1 and Sixth Revised Straw Proposal.  p.42.  Accessible at DraftFinalProposal-SixthRevisedStrawProposal-ResourceAdequacyEnhancements.pdf (caiso.com)

[3] CAISO Department of Market Monitoring.  Comments on Resource Adequacy Enhancements Fifth Revised Straw Proposal. pp.5-6.  Accessible at DMMComments-ResourceAdequacyEnhancements-FifthRevisedStrawProposal.pdf (caiso.com)

[4] CAISO Department of Market Monitoring.  Comments on Resource Adequacy Enhancements Sixth Revised Straw Proposal. pp.3-4

[5] Comments of the Public Advocates Office on the Resource Adequacy Enhancements Sixth Revised Straw Proposal. Accessible at  California ISO - All comments (caiso.com)

[6] CAISO.  Extended Day-Ahead Market Draft Final Proposal.  pp.39-40.  Accessible at DraftFinalProposal-ExtendedDay-AheadMarket.pdf (caiso.com).

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

 Cal Advocates does not have comments on this section at this time.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

 Cal Advocates does not have comments on this section at this time.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

 Cal Advocates does not have comments on this section at this time.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

 Cal Advocates does not have comments on this section at this time.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

 Cal Advocates does not have comments on this section at this time.

Idaho Power Company
Submitted 11/22/2022, 04:36 pm

Contact

Kathy Anderson (kanderson2@idahopower.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

Idaho Power appreciates the opportunity to comment on the draft final proposal. Idaho Power generally supports the proposal, but there are still areas where Idaho Power believes improvement must continue to occur. The EDAM extends the EIM concept where all participants continue to retain all the reliability responsibilities. In addition, each transmission service provider inside an EDAM BAA retains its existing Open Access Transmission Tariff. This makes the overlay of the market challenging to ensure minimal cost shifts occur between transmission customers. The EDAM must not degrade reliability by allowing participating BAAs to lean on the capacity of others especially in stressed conditions, nor allow transmission customers to avoid transmission costs required to be paid under the OATT for transmission usage. Idaho Power respectfully submits the comments below.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

Idaho Power generally supports the participation model proposed. In this section, CAISO introduced the concept of a transmission requirement for suppliers. Idaho Power appreciates CAISO being receptive to transmission service providers opinions in this area. The EDAM is a unique design, which is distinctly different than an RTO. OATT transmission still exists and under the OATT there is no use of the transmission system that is not compensated by a transmission customer. If there is use of the system in which a transmission customer does not have transmission rights, they are subject to unreserved use under the OATT. In the November 14th stakeholder meeting, CAISO added to the proposal to allow a generator to either be (1) a designated network resource of the load in the EDAM BAA in which they are located, (2) obtain at a minimum monthly firm point-to-point transmission from that EDAM BAA, (3) hold a legacy transmission agreement, or (4) obtain an after-the-fact transmission charge for the awarded amount above the firm rights held to account for that full usage at the Transmission Service Providers Daily Firm point-to-point rate. Idaho Power supports this concept as it obtains a similar outcome of physically reserving the transmission before the market optimization and ensuring all transmission customers continue to pay for transmission that is required to be paid under the OATT for usage of the system.  

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

The first step in ensuring confidence in transfer is to ensure that every BAA participating in the market has enough sufficient supply to meet its own needs absent the market. Each BAA must forward procure enough capacity to meet its demand, ancillary services, uncertainty, and flexibility before the market runs to allow diversity benefits among participants. Absent a common resource adequacy program in which all participants have the same forward performance requirements, a strong resource sufficiency test that incentivizes forward procurement of physical capacity becomes the next option to ensure the market does not become a mechanism for an entity to avoid forward procurement or generation investment costs.

Idaho Power generally supports the design elements CAISO has proposed as they enhance the confidence of market transfers. However, allowing an entity that fails the RS test (by failing to procure enough capacity to meet its own needs before the day ahead market) to cure that failure regardless of the MW amount of failure through available supply in the market starts to erode the confidence of transfers. Idaho Power discusses this further below in the resource sufficiency comments.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Idaho Power has additional comments on this area.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

Idaho Power appreciates CAISO recognizing that under an EDAM model, there is a risk that short-term transmission sales will decrease. This is because as the market seeks to optimize more transmission, there is less transmission available for bi-lateral sales after the market runs. A reduction in short-term transmission revenue may impact the rate long-term users of the transmission system pay under the OATT. It is important that a transmission provider is not financially harmed through the participation of EDAM through lost revenue or revenue cost shifts among its transmission customers.

Idaho Power against requests that monthly firm and non-firm historical revenue be included in the recoverable amount. This is especially important to avoid any revenue at risk that may occur upon entry. There is uncertainty around how behavior or market participants will change with a day ahead market option and waiting for a proposed two years to re-evaluate creates potential lost revenue that cannot then be recovered. This inclusion of monthly duration revenue does not increase the risk of over-recovery given the true-up mechanism proposed by CAISO. Under the proposal, the transmission service provider is only going to be allowed a certain amount of revenue recovery and should OATT sales continue as they were before, this will be trued up and adjusted. However, it does mitigate the risk of under recovery that could occur.

The proposal also discusses a re-evaluation at two years of the transmission revenue compensation. Idaho Power notes that while a re-assessment of the amount of revenue recovered through the market may be appropriate to review after two years in order to adjust the at-risk percentage, Idaho Power would oppose any movement to eliminate a recoverable revenue component after two years. As long as entities maintain an OATT, it is important that the market compensate transmission service providers for the transmission that is utilized by the market and thus is no longer available under the traditional OATT sales framework.

Idaho Power appreciates CAISO’s proposal to continue including new transmission builds into the recovery mechanism. Transmission is the key to market connectivity and diversification savings. New transmission will increase the benefit to all participants. Idaho Power is currently building transmission and once that transmission comes into service, it becomes included in Idaho Power’s transmission revenue requirement in Idaho Power’s FERC approved OATT formula rate. Given the purpose of the recovery mechanism proposed, Idaho believes including a recovery percentage applied to new transmission is appropriate as market usage of that transmission will decrease the potential revenue sales of that new transmission capacity.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

Idaho Power’s preference is a biannual true-up mechanism.  That said, Idaho Power can support the annual true-up opportunity proposed in the paper provided the true-up amount is determined before the end of February. 

In addition, Idaho Power wants to stress the importance that any money paid to the transmission provider for the at-risk revenue needs to be a pure transmission revenue payment to the TSP and in a separate settlement code than any other charges. This transmission revenue must not be netted between what an entity’s load pays versus what the entity’s TSP receives. These are distinct costs and revenues to different functional areas of a company (user of the system vs provider of the system) and under transmission rate making principles should not net out.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

Sufficiency test with strong failure consequences to incentivize the forward procurement of physical resources is extremely important in the EDAM. It’s imperative that each EDAM participant can stand alone from a physical supply perspective to prevent capacity cost shifts and retains a focus on reliability. Failure to forward procure and bring enough physical resources diminishes the reliability of service to all loads in the footprint, especially in stressed conditions.

Idaho Power appreciates the diversity benefit the EDAM could bring.  However, Idaho Power does not believe that a BA that fails the day ahead RS test should be allowed financially cure any size failure.  Such allowance diminishes the incentive to forward procure and allows entities to lean on the excess capacity in the market. And it provides fewer physical resources for others should an unexpected or unplanned event occur.

Idaho Power fully supports limiting the resources that count towards the RS test to owned or contracted supply.  The concept of allowing an entity to cure and purchase from excess supply in the market event at an administrative price and at any size defeats the very purpose of the RS test.

Idaho Power fully supports and appreciates the need for some amount of procurement from the market be allowed if voluntary supply is available at administrative prices.  Idaho Power also supports the escalation of administrative penalty prices based on the severity, Idaho Power does not, however, support a lack of a cap of the amount of MW that can be cured. The depletion of the physical supply that would be allowed by an unlimited “buy” option is concerning and will ultimately impact reliability. In addition, what is the solution should two or more EDAM participating BAAs fail? How will any excess supply be allocated especially when such supply is not large?

Idaho Power continues to request that CAISO cap the amount of supply that can be procured at administrative pricing in the day ahead market by a failed entity.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

Idaho Power appreciates the tiered approach proposed by CAISO given the uncertainty of day-ahead forecasts.  Idaho Power supports the Tier 1 proposal. However, as stated above, Idaho Power does not support the unlimited MW value ability to cure even if voluntary supply exists.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

Idaho Power supports the pooling of EDAM entities passing the EDAM RSE to be evaluated as a pool for the WEIM RSE. Once the day ahead market decisions are made, it would be very difficult for an EDAM BAA to pass the WEIM RSE as a standalone BAA without procuring additional resources and reducing (if not eliminating) any diversity benefit recognized in the day ahead. However, Idaho Power again reiterates its concern with an entity’s ability to financially cure any amount of failure from the market by paying an administrative penalty price. Idaho Power again asks for some cap on the amount of energy that can be cured from the market regardless of voluntary supply to avoid turning the decision to pass the RS into a financial risk and cost assessment.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

Idaho Power understands the desire for those market participants that have a must offer obligation of all RA supply to have the ability to protect some of that capacity for reliability issues in that Balancing Authority. Idaho Power does not have comments specifically on the proposed tools but would like clarification from CAISO as to how export transfer constraint will impact the RS test of the entity that enables it. Today, an WEIM entity can utilize ABC to hold back capacity from the market, but that capacity does not count towards any RS tests. How will the capacity above the export transfer constraint be treated in the RS test? Idaho Power believes that if ABC is excluded from the test, capacity exceeding the export transfer constraint should be treated in a similarly.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

Idaho Power requests CAISO provide clarification on the definitions of the Tiers outlined in the EDAM RSE deficiency section. The reference to the ability of the market meeting or not meeting demand was not clear. Is the CAISO suggesting that an entity that fails the RS can cure through a Tier 3 administrative penalty even if the market cannot solve or is infeasible? Some additional clarification in this area would be appreciated.

In addition, Idaho Power understands the desire to credit back the administrative surcharge for hours an entity passes to try to decrease the cost to the failing entity, but it appears this design provides the incentive to avoid a bi-lateral forward procurement of energy in 16-hour blocks that occurs today, which limits the actual energy brought to the market through those purchases. CAISO states that the crediting approach is akin to the bilateral contract construct in that during the hours the energy is not needed to meet a BAA’s own obligation, it can be re-marketed or used to displace resources internal to that BAA. While that is correct, the difference is also that in the bilateral construct, the actual physical energy is purchased and there is no option to avoid the cost. The mechanism proposed by CAISO appears to financially incent an entity to forego the bilateral purchase to avoid the cost of that block purchase and instead buy through the market ONLY in the hours it really needs the energy at a lesser price. This provides financial incentive for an entity to avoid a 16-hour block purchase and allows for an entity to turn passing the RS test into a financial analysis of whether to pass the RS test or to fail and cure financially in the market. This appears to weaken the incentive to forward procure, come sufficient to the market, and not lean on the capacity others have brought. Idaho Power requests that the crediting mechanism not be implemented at the start of EDAM but properly incent the entity to pass the RS test through bringing proper supply to meets its own obligations. The cost of buying from the market should not be cheaper than forward procurement options available today before a market run.  

Idaho Power encourages CAISO to view all aspects of its Resource Sufficiency test proposal to ensure that it does not incent systematic leaning and energy arbitrage opportunities for entities.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

Idaho Power has no additional comments in this area.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

CAISO elected with stakeholder support to move MPM and other price formation enhancement discussion to another stakeholder process, the Price Formation Enhancement. Idaho Power requests that CAISO confirm the Price Formation Enhancement stakeholder process will still be completed within the EDAM timelines? There are critical EDAM market design issues (including MPM enhancements) that entities will need resolved before commitment to EDAM can occur.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

Idaho Power appreciates CAISO recognizing that many entities do not have experience with convergence bidding. The EDAM is a unique design from a traditional ISO/RTO structure in that there is no single Balancing Authority or common transmission service provider OATT. EDAM entities will retain those responsibilities outside the market. Idaho Power is concerned that convergence bidding could create an opportunity for virtual bidders to gain significant profits paid through uplift costs to loads.

Idaho Power does not support an EDAM entity being required to implement convergence bidding within any specific timeline. EDAM is a hybrid model combining traditional OATT service with the ability to economically displace in the day-ahead resources an LSE already owns (or contracted for) to serve its load.

The CAISO uses convergence bidding to reduce the incentive to over- or under-schedule demand. In contrast, the OATT requires customers to meet their forecasts or face penalties. There is no discussion as to why potential EDAM Entities would have the same challenges with price convergence that the CAISO does. Under the OATT, the issue of over or under scheduling can be addressed by requiring customers to come forward with resources to meet the forecast. This is what is done today in the EIM with the balanced schedule requirement that is then rolled into the EIM Entity base schedule. To appropriately allocate resource sufficiency and imbalance reserves, it is possible that OATT customers in EDAM will have an obligation to meet their share of a planning reserve margin in addition to the forecasted amount.

The CAISO has stated that by using offsetting virtual supply and demand bids, market participants can hedge congestion costs or earn revenues associated with differences in congestion between different points within the CAISO system by placing virtual demand and supply bids at different locations during the same hour. In EDAM, however, transmission customers should receive the same or better protection if the EDAM transfer revenue and congestion revenue is allocated from the EDAM BAA directly back to OATT customer to help hedge against congestion that rises in the system. In other words, the market design is addressing this needed congestion protection for all OATT customers on an equal basis without the use of convergence bids that allow not only the OATT customers themselves, but also third parties to engaging in the virtual bidding activity. Simply stated, the OATT construct is not CAISO transmission service. The transmission provider is still providing the service of moving resources to loads at a Commission-approved fixed price.

Idaho Power agrees with the concern NV Energy noted in its previous comments that if there is a pattern of price differences, virtual bidders can reap substantial profits, which are paid for as an uplift by loads. This is an unnecessary cost to load given the OATT framework. With no data on EDAM operations, with the potential for significant changes in new market designs and new market participants, it is unnecessary to make a commitment to implement convergence bidding in a non-CAISO BAA participating in EDAM.

Idaho Power agrees with NV Energy that the decision to support convergence bidding within an EDAM BAA should be the choice of the transmission provider and their OATT customers and not mandated or required by the CAISO design. These customers should not face exposure from financial speculators who can create substantial uplift costs that have the potential to dimmish potential EDAM benefits. Idaho Power would also support CAISO initiating a stakeholder process to consider the specific issue of convergence bidding in the EDAM after two years of EDAM operation. That real-world experience and pricing data could better inform consideration of the issue rather than an unsupported assumption that it will be a benefit in a hybrid market with different footprints for day-ahead and real-time with the continuation of the EIM.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

Idaho Power supports the proposal in this area.  

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

Idaho Power appreciates the discussions CAISO has had with stakeholders in the area of GHG. Idaho Power’s stresses that it will not support any market design that may limit the secondary dispatch but create the possibility to increase the need for bid cost recovery or other market pricing impacts. Any market designs needed to support state GHG policies should not have a negative impact to reliability or economic benefits for participants located outside that GHG region.  

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

Idaho Power has no additional comments at this time.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

Idaho Power has no additional comments at this time.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

Idaho Power has no additional comments at this time.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

Idaho Power supports the proposed allocation of transfer and congestion revenue in the draft final proposal. This revenue will be used to mitigate cost exposure to OATT customers exercising their existing rights. Idaho Power envisions that any shortfall or excess would be allocated to Measured Demand and not be retained by the transmission provider.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

As we read the settlement proposal, it is not clear whether current WEIM settlement charge codes and new EDAM settlements are going to be comingled inside of current WEIM charge codes. We would ask CAISO to consider (if they are not already) separating out charge codes directly related to EDAM activities vs. charge codes directly related to WEIM activities. This will assist EDAM entities in reviewing settlement impacts of EDAM separately from settlement impacts of WEIM and properly allocating OATT provisions to transmission customers based on the different markets.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No comments at this time.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

Interdependent Stakeholder processes – CAISO has stated that there are interdependencies between EDAM and other critical, ongoing CAISO initiatives: (1) the Day-Ahead Market Enhancements (DAME) Initiative, (2) the Transmission Service and Market Scheduling Priorities Initiative, (3) EIM Resource Sufficiency Evaluation Enhancements, and (4) Price Formation Enhancements. Several design elements of these initiatives will have a direct impact on EDAM design. Certain important elements such as price formation and system market power mitigation being addressed in another stakeholder initiative appear to have limited progress to date. To complete the EDAM design, stakeholders need a resolution of the approaches to price formation and system market power. Idaho Power encourages CAISO to increase the effort on these critical aspects of market design.

Western Resource Adequacy Program – The EDAM design needs to ensure that any obligation an EDAM entity has under WRAP program must be honored. Resources and transmission needed to fulfil the WRAP members obligations should not be infringed upon by the market. In addition, as both WRAP and EDAM evolve, consideration should be given to design elements to ensure the inter-operability of the two programs continues and does not diminish the value proposition of either program.

Joint Undersigned Entities
Submitted 11/23/2022, 04:16 pm

Submitted on behalf of
The Undersigned Entities of Balancing Authority of Northern California, Los Angeles Department of Water and Power, PacifiCorp, Portland General Electric, Seattle City Light

Contact

Tony Braun

BB&W, P.C.

 

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

See Attached.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

See Attached.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

See Attached.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

See Attached.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

See Attached.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

See Attached.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

See Attached.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

See Attached.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

See Attached.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

See Attached.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

See Attached.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

See Attached.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

See Attached.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

See Attached.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

See Attached.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

See Attached.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

See Attached.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

See Attached.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

See Attached.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

See Attached.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

See Attached.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

See Attached.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

See Attached.

Los Angeles Department of Water and Power
Submitted 11/22/2022, 05:25 pm

Submitted on behalf of
Los Angeles Department of Water and Power

Contact

Stuart Kelly (skelly@utilicast.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

Please see attached document.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

Please see attached document.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

Please see attached document.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Please see attached document.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

Please see attached document.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

Please see attached document.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

Please see attached document.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

Please see attached document.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

Please see attached document.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

Please see attached document.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

Please see attached document.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

Please see attached document.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

Please see attached document.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

Please see attached document.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

Please see attached document.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

Please see attached document.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

Please see attached document.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

Please see attached document.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

Please see attached document.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

Please see attached document.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

Please see attached document.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

Please see attached document.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

Please see attached document.

NIPPC
Submitted 11/22/2022, 01:19 pm

Submitted on behalf of
Northwest and Intermountain Power Producers Coalition

Contact

Henry Tilghman (hrt@tilghmanassociates.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

NIPPC generally supports the direction of the EDAM stakeholder process and encourages CAISO to continue to develop its proposal.

 

NIPPC also encourages CAISO to pursue further development of EDAM in a way that preserves the existing bilateral market. The existing bilateral market will be used in the forward market that allows loads to satisfy their resource adequacy requirements going into EDAM.  Loads will also rely on the bilateral market to acquire additional supplies of capacity in the event of generator contingencies following the day ahead market run. Transmission customers using their transmission service rights in the bilateral market should not be exposed to market settlements in executing bilateral transactions.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

NIPPC generally supports the requirement that generation must have transmission service in place in order to participate in the EDAM.  Initially, NIPPC is questions whether it should be sufficient for a generator to be a Designated Network Resource in order to participate in the market.  This concern stems from the traditional use of Network Transmission Service – which is to serve load.  Currently, in order to participate in off-system sales a Designated Network Resource must be undesignated and the transactions supported by purchase of point to point transmission service to support the transaction. Because Network Service rates are based on load demand, there is no disincentive for a load to designate generation resources significantly greater than its projected demand.  Ironically, much of the revenue shortfall that will be lost to transmission providers will be the sales of short term point to point purchases the merchant function of those transmission providers purchased in order to make off system sales. Going into the next phase of EDAM development, CAISO should consider whether all generation should be required to purchase firm point to point while loads would continue to be required to purchase Network Transmission Service.

 

NIPPC otherwise supports the proposed revisions to the transmission requirements for generation which allows a resource that does not have transmission service to still bid into the market subject to a transmission charge from the host transmission provider based on the daily firm point to point rate.  NIPPC strongly believes that the generator should not be required to purchase transmission service for the full day – rather the transmission charge should an hourly charge for the actual hours of market awards but based on the daily rate (i.e. a generator which is dispatched for 8 hours would pay 8/24s of the daily rate).  NIPPC recognizes that transmission providers will have to adapt their existing tariffs to ensure that generators are not also exposed to transmission charges for unauthorized use.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

No comments

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

NIPPC supports the current proposal that allows transmission customers the ability to exercise their transmission rights after the close of the day ahead market without financial impacts or exposure to market settlement.  Transmission customers who chose not to participate in the market should not be exposed to market settlements. 

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

No comments

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

No additional comments

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

NIPPC supports the proposal to allow non-resource specific supply contracts to count towards the day ahead resource sufficiency evaluation.  

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

As the West transitions to an organized day ahead market, NIPPC wonders whether if it is appropriate to continue to rely on indexes based on bilateral transactions.  What is currently a robust bilateral market with sufficient volume of transactions and number of counterparties to develop meaningful index prices may not exist in the future if market participants simply bid into the Day Ahead Market.  While market hub indices are currently a reasonable basis for calculating penalties for failure to meet the RSE, NIPPC encourages CAISO to monitor index prices (and index price development) once EDAM is implemented and be ready to move to an alternative basis for calculating penalties.

NIPPC is also concerned with the proposed allocation of RSE penalties.  Revenues from the surcharges imposed on BAAs that fail the RSE should be allocated to the generators who supply the shortfall.  Allocating those surcharges to the BAA that hosts that generation is simply a windfall to the BAA – the BAA may simply provide balancing area services to the generators who actually cure the shortfall.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

No comments

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

No comments

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

No comments

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No comments

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

No comments

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

NIPPC supports the concept of convergence bidding. NIPPC”s concern with the current proposal is that it may lead to a patchwork across the west where some balancing areas have convergence bidding and others are transitioning to convergence bidding on inconsistent timelines. NIPPC suggests that the CAISO provide for specific windows for balancing areas to begin the transition to convergence bidding.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

NIPPC supports broad participation by generation resources in balancing areas that have elected not to participate in EDAM.  Just as generators in balancing areas that join the EDAM may choose not to participate in market settlements, generators in balancing areas that choose not to join EDAM should still have opportunities to bid into the EDAM.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

No comments

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

No comments

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

No comments

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No comments

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

No comments

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

No comments

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No comments

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

No additional comments.

Northern California Power Agency
Submitted 11/22/2022, 04:48 pm

Contact

Michael Whitney (mike.whitney@ncpa.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

NCPA continues to have concerns with the proposal to subsidize transmission providers for estimated lost revenues based on historical activity. CAISO transmission access charge rates are some of the highest in the country, and will continue to increase due to a number of factors, including upgrades required to support policy objectives. NCPA understands that implementing transmission rate fees or charges for EDAM transfers could hinder the market optimization and prevent maximum transfers, thus a hurdle-free transmission framework is more economically efficient, but in light of the significant savings that entities throughout the Western Interconnection are projected to receive as a result of EDAM implementation, NCPA believes that subsidizing transmission providers for estimated lost revenue is over reaching (especially if there is little to no compensation provided to offset the cost of transmission in the CAISO).  As such, NCPA appreciates CAISO’s new proposal to help mitigate and reduce subsidies to transmission providers, and disruption of the OATT framework, by requiring all supply to secure network, point to point, or some other high quality transmission service up front to participate.  NCPA looks forward to working with CAISO to evaluate and minimize requested subsidies.

 

NCPA is concerned with the aggressive timeline targeting February 2023 for approvals of the design, and 2024 go-live considering that two major proposals were just included in the draft final version of the proposal. At minimum, NCPA suggests going live in fall 2024. NCPA recognizes that entities may be enticed to push for a spring 2024 go-live due to the potential economic and reliability benefits the program facilitates, but NCPA feels it would be dangerous to release such a massive market change prior to summer after such an aggressive implementation schedule and continued resource scarcity.  NCPA supports sound design and implementation over expediency.

 

NCPA also supports the new element of the proposal that will allow external supply to participate in the EDAM, provided such supply satisfy certain conditions; particularly the requirement to be modeled in the EIM. These requirements will help prevent any unintentional double counting and increase grid reliability.

 

Lastly, NCPA requests for CAISO to conduct workshops to help market participants better understand how EDAM and EIM benefits are calculated, and requests CAISO provide more transparency and data supporting the results to the extent possible. NCPA’s understanding is that EIM benefits are largely due to least cost dispatch, meaning that EDAM entities benefit from abundant CAISO renewables, while CAISO renewable off-takers enjoy reduced economic and operational curtailments of their resources. Some of the recent benefit reports appear to show the benefits skewed toward non-CAISO participants; as such, NCPA desires to better understand what is behind those results, so it can confirm that EDAM benefits are equitable and fair.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

No comment. 

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

No comment. 

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

No comment. 

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

Please see comment 1. 

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

Please see comment 1. 

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

No comment. 

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

No comment. 

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

No comment. 

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

No comment. 

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

No comment. 

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No comment. 

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

No comment. 

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

No comment. 

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

Please see comment 1. 

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

No comment. 

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

No comment. 

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

No comment. 

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No comment. 

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

No comment. 

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

No comment. 

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No comment. 

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

Please see comment 1. 

NV Energy
Submitted 11/21/2022, 02:19 pm

Contact

Kiley Moore (kiley.moore@nvenergy.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

NV Energy appreciates the opportunity to comment on the Extended Day-Ahead Market (EDAM) Draft Final Proposal (DFP). NV Energy commends the CAISO staff, market participants, and regulators who have participated in the intensive and collaborative stakeholder process. While NV Energy might prefer a more direct path to the Regional Transmission Organization (RTO) participation required by Nevada State law, it understands that an incremental approach is favored by many of our neighboring entities. NV Energy agrees with CAISO’s statement, “[b]y leveraging the significant resource diversity and transmission connectivity that exists between the major supply and demand regions of the West, the [Western Energy Imbalance Market (EIM)] has clearly demonstrated the value of strong collaboration across a broad regional footprint.”

Recognizing that the EIM remains a work in progress, especially with respect to the resource sufficiency evaluation, wheel-through transmission requirements, price formation, and implementation of a truly independent governance structure, NV Energy believes that a well-designed day-ahead market can bring additional economic and reliability benefits, if that market can attract broad, diverse participation. NV Energy also understands the desire to move expeditiously on EDAM development. Given that the CAISO Staff will only be “briefing” the EIM Governing Body and the Board of Governors in December; the CAISO should clarify how much discretion will remain to modify the market design elements as additional discussions and tariff drafting proceed after the “final” proposal.

These comments are not meant to be a comprehensive statement of NV Energy’s position on the EDAM. It hopes that they are of assistance as the CAISO team finalizes the EDAM proposal.  As explained further below, NV Energy continues to have concerns with the following elements of the DFP:

  1. The untried and not fully designed imbalance reserve product. NV Energy submitted comments on this issue in response to the Fourth Revised Straw Proposal in the Day-Ahead Market Enhancement initiative.
  1. The mandate to implement convergence bidding in an EDAM Entity’s Balancing Authority Area (BAA) after only one year without a demonstration that benefits will outweigh the significant risks of substantial uplift payments and without transitional protections such as position limits.
  1. The failure to address fully the specific gas management issues of the Desert Southwest and the failure to consider modifications to the approach for commitment costs and default energy bids for use-limited gas peaking units.
  1. The lack of specificity regarding the metering requirements associated with current EIM non-participating resources that will be converted to EDAM participating resources.
  1. The need to better define participation responsibilities. For example, if a load serving entity (LSE) must participate with their generation and if a LSE can schedule their own load, the CAISO should develop the functionality for the LSE to be assigned their proportionate share of the resource sufficiency evaluation, especially if the failure consequences are financial.
2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:
  1. Transitional Mechanisms

This DFP extends the EIM’s voluntary participation model to the EDAM. EDAM. Entities must participate in the EIM, but EIM Entities are not required to participate in the EDAM. In addition, EDAM Entities can exit the market with no exit fees after a six-month notice period. NV Energy supports this overall structure.

An important transitional measure that will apply to EDAM is an extension of the CAISO’s day ahead price correction authority from five business days to 10 business days for a three-month period following implementation. NV Energy supports this measure, but suggests it should be extended to the real-time market as well to respond to any unintended consequences. This is especially important as Federal Energy Regulatory Commission (FERC) has eliminated the possibility of retroactive adjustments not supported by existing tariff authority.

  1. Participation Model

In the EDAM, all resources within the associated BAA will become participating resources and will be settled through the market. The DFP suggests that non-participating resources currently represented by a EIM Entity scheduling coordinator could either: (1) establish a direct scheduling coordinator relationship with the CAISO or (2) be represented by the EDAM Entity scheduling coordinator as done in the WEIM today and recommends that as a starting point, the EDAM Entity will be responsible for bidding and self-scheduling the demand within its BAA into the day-ahead market. NV Energy notes this is a significant change from the EIM paradigm and will require significant adjustments to the EDAM Entity’s Open Access Transmission Tariff (OATT).

In its comments on the Revised Straw Proposal, NV Energy requested,

 

During a recent stakeholder meeting, NV Energy inquired as to the metering and telemetry requirements that will be required of these new participating resources. The CAISO should clarify the contractual, metering, and telemetry requirements that will be expected of current OATT customers.

NV Energy repeats the request that CAISO specify the requirements that will be required of these new participating resources.

The DFP also states that it is possible to enable individual LSEs within the EDAM BAA to represent their demand in the market separately from the rest of the BAA’s load. The individual LSE would need to work with the EDAM Entity and the CAISO through the implementation process to model its load separately. Separating individual LSEs within an EDAM BAA will require separate metering that satisfies the standards of the EDAM Entity and the CAISO.

If an LSE must participate with their generation and if a LSE can schedule their own load, the CAISO should develop the functionality for the LSE to be assigned their proportionate share of the resource sufficiency evaluation. Particularly if the failure consequences are financial, directly assigning all of the participation responsibilities and consequences to the LSE, could limit OATT customers leaning on the resources of the transmission provider.

  1. Transmission Associated with Supply Offers

The DFP introduces a requirement that supply offers into the market must have associated transmission reservations. In particular, a resource must be a designated network resource using network transmission under the terms of an OATT, have reserved firm point-to-point transmission, or have a legacy transmission contract. If the resource does not have pre-existing transmission service, the DFP proposes that the resource must reserve firm point-to-point transmission service of at least one month in duration to the EDAM entity border. The DFP recognizes that in approving the EIM design, FERC did not require a transmission reservation for generators to participate.  

NV Energy notes that at this time all of the resources in Nevada have associated transmission reservations. We do not have a third-party resource without an underlying transmission reservation participating in the EIM. This is not surprising as it would be difficult to finance construction of a unit based only on EIM revenues. The resource adequacy structure in the West is predicated on bilateral contracts between suppliers and LSEs with the supporting transmission to ensure delivery. NV Energy’s primary concern is that resources qualifying for the EDAM resource sufficiency evaluation, such as a geothermal unit in Nevada under contract to a California LSE, be required to maintain their long-term firm point-to-point reservations. Any change in this approach would cause a dramatic cost shift and bring into question the EDAM value proposition.

With respect to the CAISO’s new proposal that a generator, without a resource adequacy contract supporting an LSE’s resource sufficiency obligation, must reserve transmission to bid at their node, NV Energy questions whether the month-long firm point-to-point to a specific border location is the correct approach. CAISO should not limit the ability of entities to access what may be scarce available transfer capability (ATC) for their resource sufficiency showing by requiring a supplier simply bidding into the market subject to the EDAM optimization to hold a path they may not use. If it is simply a measure of ensuring no free ridership, could the CAISO achieve the same objective by simply requiring a payment to the transmission provider equivalent to a daily firm OATT rate? Those funds could then be credited to the transmission revenue requirement similar to the payments for other short-term firm or non-firm reservations.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

The DFP no longer proposes a lower priority for transfers to EDAM BAAs that fail the EDAM resource sufficiency evaluation (RSE) due to the practical implications of distinguishing a lower priority transfer in such circumstances. NV Energy supports this change as limiting transfers during tight times, if the market can provide access to additional supply, is an unnecessary consequence. The introduction of tiered financial consequences seems just and reasonable consequence if an entity fails the EDAM RSE.

The proposed design recognizes that EDAM Entities can reserve supply in excess of their RSE obligation to manage and respond to reliability conditions within their BAA because each EDAM Entity retains its reliability function and obligations. The design further introduces a net EDAM export transfer constraint that permits the EDAM Entity to manage the amount of internal supply that can support EDAM export transfers out of the BAA. This is an additional tool available to the BAA to manage grid reliability. 

As noted in comments on the Revised Straw Proposal, NV Energy supports the consideration of a net EDAM transfer export limit constraint. An EDAM BAA would be able to hold back capacity in excess of its RSE. That ability, coupled with an EDAM Entity’s ability to apply the constraint to limit the net export to the RSE capacity and the EDAM BAA’s RSE requirement, should provide confidence that these transfers will be supported in EDAM and not curtailed if uncertainty materializes. The DFP does not clarify how the constraint would be applied. NV Energy requests more detail about whether the constraint would affect only resources owned or for which the output is purchased by the EDAM Entity or if it would limit exports from third-party generators and purchased supply in the EDAM Entity’s BAA. The later is consistent with the OATT procedures for a transmission provider to redispatch third-party designated network resources, but more detail needs to be developed under what circumstances would such a constraint be triggered.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

In the EDAM, transmission providers will continue to maintain their OATTs. The proposed transmission availability in the EDAM design seeks to maximize the amount of transmission capability made available to the market. NV Energy supports this overall framework and agrees with the comment on page 3 of the DFP that, “[t]ransmission availability to the EDAM is essential to support energy transfers across interties between participating balancing areas and realize the full benefits of the market.”

That having been said, the DFP, “continues to support the transmission “buckets” framework as a simple way to distinguish characteristics of how transmission is made available to the market by transmission customers and transmission providers, while recognizing the nomenclature may evolve” and the “design provides transmission customers clear pathways for exercising their transmission rights through the day-ahead market, releasing those transmission rights to the market, or retaining their ability to exercise those rights after the market has run.”

NV Energy questions both the “simplicity” and “clarity” of the CAISO’s transmission bucket descriptions. The DFP focus on buckets and pathways, tends to blend Network Integration Transmission Service (NITS) and point-to-point transmission service which have distinct rights and obligations. The statement in the DFP at page 37, “[t]he revised straw proposal introduced three different “pathways,” or options, for how bucket 2 transmission customers could exercise their transmission rights or otherwise make their rights available to support EDAM transfers” clearly suggests that these pathways are only associated with firm point-to-point (Bucket 2) reservations. On the next page, however, the DFP, in discussing pathway 1, includes both NITS and point-to-point customers. Finally, in discussing pathway 2 on page 39 of the DFP the CAISO only refers to “transmission customers” when this path is limited to point-to-point customers with reservations of a month or longer. The confusion continues on page 40, when CAISO states “[u]nder Pathway 3, firm and conditional firm point to point transmission rights that are not scheduled by the day-ahead market run (10:00 a.m.) become available to the EDAM to support optimized transfers.” Thus, the DFP does not discuss directly that NITS also would be broken out into: (a) scheduled by 10 a.m. (pathway 1) and (b) unscheduled by 10 a.m,, subject to later modification (pathway 3). NITS customers have transmission reservations for their peak load, and the difference between monthly usage and the NITS customer’s peak load can differ significantly allowing for additional capacity to be optimized by the market. Unscheduled NITS, especially into transmission constrained areas, such as northern Nevada, will be essential to achieving market benefits and reliability.  

In comments, on the Revised Straw Proposal, NV Energy sought to characterize EDAM transmission as follows:

  1. Self-Scheduled transmission associated with the RSE. This would be schedules from both NITS and point-to-point customers to loads and exports. Examples would include a generator in Nevada exporting to California on firm point-to-point transmission or a NITS customer with import rights moving their WSPP Schedule C purchase from the Nevada border to their network load.
  1. Self-Scheduled transmission not associated with the RSE. Another form of Self-Schedule transmission could be point-to-point transmission service that is reserved long term that doesn’t support a specific resource for an EDAM Entity’s RSE. This type of transmission usually supports bilateral daily transactions that may be out of the market.
  1. Transmission associated with “bid range”. This is a significant change from OATT practice. NV Energy could sell the capacity from a gas unit to an external EDAM Entity along with the point-to-point export rights. Rather than self-schedule the resource, the purchaser would bid it into the EDAM and receive credit towards its own RSE obligation. This will allow the unit to be dispatched if needed, but to be displaced if a less expensive source of supply is identified in the market optimization to serve that load.
  1. Assignment to CAISO. The CAISO proposes that a customer with a firm point-to-point reservation of a month or longer duration could make that transmission available to the CAISO (similar to the assignment process under the OATT) in exchange for potential congestion rent payments.
  1. Firm Available Transfer Capability – this is transmission capacity that has not been sold.
  1. Unscheduled transmission (non-firm ATC) – this is transmission that has been set aside or reserved for both NITS and point-to-point customers but was not scheduled by 10 a.m. day ahead. For example, a NITS customer may have a peak forecast for the year of 50 MW, which requires NV Energy to hold that amount for a potential schedule, but the actual load that day is only 30 MW. CAISO’s proposal is that the 20 MW would be released to use in the optimization. If the customer comes back between day-ahead and real-time and increases the schedule to 35 MW, CAISO’s optimization software would redispatch to accommodate the additional demand.
  1. Transmission associated with Transmission Reserve Margins (TRM). NV Energy and other EIM entities utilize a TRM, to meet its obligations under the Western Power Pool Reserve Sharing Agreement. A total TRM of 375 MW is allocated 175 MW to the Sierra Pacific northern system and 200 MW to the Nevada Power southern system. TRM is not made available to the market.
  1. Transmission associated with pre-OATT existing contracts or point to point transmission service agreements that are not used as a part of an EDAM Entity’s RSE could be included or “carved out” depending on the underlying contract rights. If carved out, the transmission could be assigned a Contract Reference Number similar to the Transmission Rights and Curtailment Instruction process under Section 16 of the CAISO Tariff.

In the prior comments, NV Energy proposed that transmission associated with TRM not be included in EDAM to ensure there is transmission capacity available to meet system emergencies. The DFP “supports the EDAM Entity’s participation in reserve sharing programs and clarifies that the EDAM Entity can specify under its OATT how it will deduct from the amount of firm ATC released to the market ATC associated with its participation in these programs.” NV Energy greatly appreciates this important commitment.

Other than potential for confusion or misinterpretation, NV Energy does not see any substantive conflict with the DFP’s approach to EDAM transmission availability. These comments should be viewed as NV Energy’s attempt to express the same concepts with greater delineation. NV Energy recognizes that this is a challenging topic that has been the subject of extensive stakeholder discussions and will need to be reflected clearly and accurately in the Final Proposal and the CAISO Tariff.

As noted in the DFP, only an OATT transmission customer with a firm point-to-point reservation of a month or longer could exercise pathway 2 and assign the capacity to the EDAM in exchange for a percentage of transfer or congestion revenue:

 

The transmission rights eligible to be released to the market initially are long-term (one year and longer) and monthly firm and conditional firm point to point transmission rights. These transmission rights are of longer duration and reasonably can be registered with the ISO to facilitate their release to the market without adding significant complexity and other challenges. The transmission customer could determine, on a daily basis, whether to make the full amount or only a portion of its registered transmission rights available to the EDAM for the day or a longer timeframe. The transmission customer would receive transfer revenue accrued directly from the ISO for the duration of the capacity’s release to the market. NITS transmission rights would be ineligible for pathway 2 because under the OATT these rights are tied to a designated network resource, and if the resource is not scheduled to serve load it does not have transmission rights that can be released to the market.

NV Energy supports this approach. A number of factors justify the limitation to firm point-to-point reservations of a month of longer including:

  1. NITS customers cannot assign transmission capacity as it is only used for load service based on actual load in the interval.
  1. Normally, CAISO as an independent system operator, would not be an eligible customer. This is a special exception designed to facilitate identified market activities, and the limitation does not take away any transmission customer’s right to reassign transmission to other eligible customers.
  1. Especially at the start of a new market, it may be important not to create an incentive for customers with short term transmission reservations to remove valuable transmission capacity from the bilateral market which would limit the ability of LSEs to engage in short term bilateral procurement to meet RSE requirements.
5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

NV Energy agrees that EDAM Entity transmission service providers may face the potential risk of foregone transmission revenues based upon decreased sales of short-term transmission because they have made transmission available to the EDAM. Transmission customers that purchase short-term firm or non-firm service through Nevada to participate in the CAISO day-ahead market today, may simply bid into the EDAM at the generator’s node. The DFP provides that transmission revenues recoverable through the EDAM would include:

  1. historical revenues associated with sales of non-firm and short-term firm point-to-point transmission services (wheeling access charge revenues for the CAISO),
  1. revenues attributable to similar transmission services on new-build transmission facilities that increase transfer capability between EDAM BAAs, and
  1. revenues associated with transfers wheeling through an EDAM entity’s transmission system in excess of its EDAM imports and exports.

The EDAM recoverable transmission revenue amounts would then be allocated to gross load across the EDAM footprint, with the understanding that each EDAM entity would not be allocated its own EDAM recoverable transmission revenues. There would be an annual true-up to support actual revenue recovery by individual EDAM entities. NV Energy supports these three categories of revenue recovery.

  1. Historical Sales

The revised straw proposal recommended that the EDAM recoverable transmission revenues be only those associated with historical transmission sales to third parties, not sales to the EDAM entity’s merchant function. It further proposed that the following non-firm point-to-point transmission products, which may have lower sales volumes, would also be eligible for inclusion in the EDAM recoverable transmission revenues: (1) hourly non-firm point to point, (2) daily non-firm point to point, (3) weekly non-firm; (4) hourly firm point to point (if product is offered by the transmission provider); (5) daily firm point to point; and (6) weekly firm point to point – these are appropriate products.

As to timeframe, the DFP provides for each EDAM BAA transmission provider to calculate its BAA’s EDAM recoverable transmission revenues based on its average FERC-approved (or applicable regulatory authority-approved) historical transmission revenues for non-firm and short-term firm point to point transmission services for the most recent three years. NV Energy notes that it does not have a “FERC approved” revenue credit for short term point to point transmission sales. NV Energy would propose that each EDAM Entity supply the CAISO with a worksheet identifying the applicable three years average revenue credits from short term point to point transmission sales. The CAISO would then post these submissions to ensure transparency.

  1. New Transmission Builds

The second component eligible for transmission revenue recovery through the EDAM is associated with new transmission construction approved via applicable regulatory processes. NV Energy seeks clarity as to what CAISO means by “applicable regulatory processes.” Is this through an established Integrated Resource Plan (IRP) approval? For example, NV Energy’s Greenlink projects were not approved or cost allocated in any regional or interregional transmission planning process, but were approved by the Nevada Commission. These projects increase transmission interchange transfer capability between Nevada and external BAAs. Does the Nevada Commission’s approval through the integrated resource planning meet the “applicable regulatory process” as defined in the DFP? NV Energy seeks confirmation in the Final Proposal that Greenlink and similarly-situated products would be eligible for partial cost recovery of its eligible transmission revenue recovery through EDAM.

The amount of new transmission upgrade revenue requirement that would be recoverable through the EDAM is limited to three-year average of the non-firm and short-term firm point to point historical revenues as a ratio to the EDAM recoverable transmission revenues associated with third-party sales on the new upgrade to the total EDAM Entity transmission provider revenue requirement. NV Energy seeks confirmation that the calculation encompasses the following three steps:

  1. Determine historic ratio of the six categories (1) hourly non-firm point to point, (2) daily non-firm point to point; (3) weekly non-firm; (4) hourly firm point to point (if product is offered by the transmission provider); (5) daily firm point to point; and (6) weekly firm point to point) to total TRR
  1. determine incremental TRR associated with new transmission facility that increases interchange transfer capability; and
  1. apply ratio to the incremental TRR.

Again, this will require informational showings as incremental TRRs may not be readily apparent.

  1. Wheeling

The DFP provides that in those limited periods where an EDAM Entity’s wheel-through transactions exceed the sum of their imports and exports, the EDAM Entity would be compensated for the excess transmission use at the EDAM Entity’s filed and approved non-firm hourly point to point transmission rate. As noted in our comments on the Revised Straw Proposal, NV Energy strongly supports compensation for excess wheeling.

The DFP states that the EDAM recoverable transmission revenues, across the three components, are viewed together, and to the extent that the actual revenues through OATT sales exceed the historical EDAM recoverable transmission revenues, those revenues in excess of component 1 would be utilized to offset recoverable revenues through components 2 or 3 described above. While NV Energy would prefer that the wheel-though be treated as incremental revenue to the transmission service provider, at this time, it does not oppose the overall structure of the EDAM recoverable revenue package as a balance between different interests.

  1. Methodology

There are two key questions regarding calculation of the EDAM recoverable transmission revenues: (a) across what time period is the historical at risk EDAM recoverable transmission revenue derived; and (b) how often is the historical at risk EDAM recoverable transmission revenue amount updated? NV Energy would postulate a third question – what is the level of revenue credit reduction that should be assumed to establish the initial EDAM rate?  The EDAM Entity will continue selling transmission service. As such, it is not logical that all short-term transmission service sales will be foregone.

The CAISO recognizes this issue in Table 2 on page 50 of the DFP. NV Energy would recommend starting at recovering 50 percent of EDAM recoverable transmission revenue shortfall for the first year.  As stated in the proposal, there would be an annual true-up to support actual revenue recovery individual EDAM Entities. At this time, the recoverable allocation percentage should be updated to more accurately reflect the shortfall. NV Energy supports the DFP’s determination whereby year-end true-up shortfalls or surpluses would be carried over into the following year’s calculation.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:
  1. Non-Firm Transmission

The DFP states:

 

The market will not establish different levels of priorities of market schedules based on different types of non-firm transmission rights, but the EDAM entity transmission provider will continue to be the arbiter of these transmission rights, and it will retain the authority to curtail internal schedules supported by non-firm transmission as it does today, consistent with its OATT.

NV Energy requests clarification as to how this process will work. 

  1. Use of Contract Reference Numbers

This DFP states that, in addition to legacy (pre-OATT) contract rights and third-party transmission ownership rights, firm OATT transmission rights held by customers within an EDAM BAA that do not support transfers between EDAM BAAs will be afforded scheduling and settlement similar to firm transmission rights between EDAM BAAs and that the accrued internal congestion revenues will be settled with the EDAM Entity. NV Energy agrees that both transfer revenues and congestion revenues should be used to hold all OATT NITS and firm point-to-point customers harmless from EDAM congestion costs. In other words, no existing OATT customer would subsidize another OATT customer through an uplift charge. Rather any excess or payments would be settled as a congestion offset charge to Measured Demand as done for the EIM today.

CAISO maintains that a contract reference number (CRN) is necessary for an entity to self-schedule their transmission rights under EDAM so the CAISO can recognize the rights in the market optimization and schedules. The DFP then goes on to refer to this as existing transmission contract (ETC) and transmission ownership rights (ETC/TOR) treatment, NV Energy questions whether this terminology is either necessary or correct.

  • Will OATT providers and transmission customers need to set up CRN for all DNRs and Network Loads and firm point-to point transmission service agreements in addition to legacy transmission rights?
  • How would the use of CRNs account for self-scheduled secondary network service?
  • Would transmission service have a duration limitation for when a CRN would be required? i.e 1-year or longer?
  • NV Energy understands that ETC and TOR treatment are associated with the CAISO concept of a “perfect hedge. Does the CAISO agree that there will be no perfect hedge for OATT customers in EDAM and that congestion costs and Transfer Revenues will be used to hold customers harmless for intra-day schedule changes to the extent feasible, but no OATT customer will be paying uplift charges to another OATT customer?
7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

The CAISO proposes that each EDAM BAA meet a resource sufficiency evaluation (RSE) to have sufficient supply to meet demand, ancillary services, and uncertainty requirements. Additionally, CAISO proposes to hold separate market optimization runs for the Integrated Forward Market (IFM) and Reliability Unit Commitment (RUC) process where the bids that are supplied in the IFM will have a must offer requirement into the RUC. The market design will achieve additional confidence and attempt to reduce resource redispatch through the transmission availability proposal to utilize all transmission in day ahead and real time. Moreover, the market will contain parameters that prevent a BAA from propagating shortfalls to other BAAs by preventing exports from a BAA experiencing a power balance constraint. CAISO’s draft final proposal to instill confidence in the market transfers is to include a day ahead imbalance reserve product that would procure nearly all uncertainty that occurs from the day ahead timeframe into the real-time fifteen-minute market.

As noted in comments on the Revised Straw Proposal, NV Energy supports all of the high-level proposed concepts to instill confidence in market transfers except the proposal for an imbalance reserve product. NV Energy remains skeptical that this product is necessary in the day-ahead market when it is essentially procuring capacity (i.e. changing the unit commitment level) while also being misaligned with the flexible ramping product design in real time. If the uncertainty products differ in design from day-ahead to real-time, NV Energy is concerned that load is procuring capacity in day-ahead that will later be decommitted in STUC.

To be clear, NV Energy is not advocating for the imbalance reserve design to change the current flexible ramping product. There are additional issues with the imbalance reserve that need to be resolved before NV Energy would be able to support this product. Instead, NV Energy believes that the flexible ramping product design should be extended to the day ahead if it is determined that it is necessary to procure all uncertainty in the day ahead market. Additionally, NV Energy proposes that CAISO consider enhancements to STUC to provide more confidence in the market overall. Stated more clearly, we should be working back from the real time market flexible ramping product rather than designing an entirely new misaligned product that may provide little to no benefit to load. Finally, NV Energy is concerned about the timing of the CAISO’s Day-Ahead Initiative and its relationship to EDAM. To have such a controversial proposal be a foundational element of EDAM presents a significant risk to the EDAM design and timeline.

For additional detail into the additional issues regarding the imbalance reserve product NV Energy submitted comments on CAISO’s Fourth Revised Straw?Proposal for the Day-Ahead Market Enhancements. In those comments, NV?Energy noted:

  • NV Energy is appreciative that CAISO is conducting a benefits study with a sensitivity analysis to determine the benefits of the Imbalance Reserve Product but recommends that CAISO provide sufficient time for stakeholders to evaluate the study results in order to provide meaningful comments before CAISO finalizes any design.
  • NV Energy would like to understand why an imbalance reserve product would be more beneficial for all market participants than must offer rules that carry into a real time market. Therefore, it is important that the benefit study show the benefits for each individual BAA rather than a footprint wide study and that CAISO explain why an imbalance reserve product is better than a must offer requirement for EDAM. 
  • If it is useful to procure additional supply for future heat waves or during west wide stressed system conditions, it doesn’t mean that the market should procure supply for this level of uncertainty during all times of the year. CAISO has proposed to procure the full imbalance reserve requirement rather than utilize a demand curve which would procure imbalance reserves based on the probability the capacity is needed in real-time. This could have a significant impact on the day-ahead prices of this product and may result in over-procurement in capacity for a large portion of the year, which could also have an impact to the real-time market prices.
  • NV Energy reiterates a request that CAISO explain the rationale for procuring up to the 97.5 percentile of uncertainty. Additionally, it is our understanding that this product is designed to procure capacity to reduce instances of operator load conformance and to establish a price for capacity that might otherwise be procured outside the market. However, it is unclear whether this product would procure too much capacity. In other words, is it necessary to procure capacity in the Day Ahead Market to cure almost 100 percent of the uncertainty?  It is also unclear if the concern with excessive load conformance is with regard to CAISO’s operators and, if so, is a more targeted solution a better approach.
  • NV Energy cannot support the proposed biddable imbalance reserve product or the proposed pricing relaxation structure. Specifically, NV Energy would like to see analysis on the pricing of this product and the impact to both the day ahead and real-time markets, the cost of implementing the product to customers, the EIM area’s monthly imbalance reserve requirement, impacts to the import/export curtailments in RUC and quantities of non-binding commitments that would result in imbalance reserve awards that would be reoptimized in real-time. Currently, CAISO is proposing a level of 98 percent price relaxation prior to the power balance constraint which is excessive. The T-60 forecast in real time for load has a 1-2 percent MAPE, forecast error for EIM today. In day ahead it is reasonable to assume that the forecasting error will become larger because the time horizon will range from 14 hours to 38 hours. Therefore, the proposed 2 percent relaxation is not reasonable. Given the fact that the Flexible Ramping Product has not operated as intended in the Real-Time Market to date, it is unreasonable to design the imbalance reserve product as a biddable product instead utilizing and relaxing prices from a demand curve. The biddable aspect of this product could be implemented at a future date, when stakeholders have sufficient time to consider all of the impacts of the design and mechanisms needed to protect customers.
  • CAISO has proposed to implement a real-time bid cap to cap the level that generators can bid in real-time when awarded imbalance reserves from day ahead. NV Energy does not support this proposal at this time. Any concerns about real-time bidding should be monitored by the Department of Market Monitor rather than creating a bid cap for generators without sufficient time to think about all of the consequences of that design. One of NV Energy’s concerns with this proposal would be the issue of gas procurement impediments due to the misaligned timeline of the Day-Ahead Market awards in relation to when gas trading occurs.

In comments submitted on September 16, 2022, on the WEIM Resource Sufficiency Evaluation Enhancements Phase 2 Revised Draft Final Proposal, the Department of Market Monitoring states:

 

If the 97.5% threshold is not actually a meaningful uncertainty target, stakeholders may want to consider a more straightforward uncertainty adder. This is because the uncertainty adder produced by the quantile regression method is likely to fluctuate significantly interval by interval and could be very difficult for BAAs to reproduce or predict in advance. A simpler adder, such as a fixed percentage of each interval’s net load, could result in much more transparent and easily predictable RSE test requirements, as well as significantly smoother transitions between RSE test requirements throughout the day. A simple percentage of load adder, such as a planning reserve margin, has a long history of being successfully utilized in the electricity industry for setting standards for forward procurement of capacity to meet uncertainty needs. It could be worth considering for the WEIM (and EDAM) as well.

In comments on the Revised Straw Proposal, NV Energy supported this reserve margin approach as a means of simplifying and enhancing the predictability of the EDAM RSE and the imbalance reserve product. We noted that it is important to remember that the EDAM RSE will need to be allocated not only to the EDAM Entity’s native load, but also must be sub-allocated to third party customers. This means the RSE must be predictable and know with enough certainty to enable these OATT customers to meet their respective targets. A reserve margin would operate similar to an average system loss factor under the OATT today enabling appropriate attribution. NV Energy continues to support the use of a reserve margin approach as a more straightforward means to address uncertainty.  CAISO’s calculations add unnecessary complexity without a corresponding benefit.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

The DFP notes that incenting EDAM entities to pass the RSE is critical, recognizing that absent a fair, equitable, robust, and stable RSE structure that creates effective consequences for failing the RSE, participating EDAM entities may not have the confidence necessary to offer surplus supply into the market, instead choosing to retain their surplus supply for managing reliability conditions. The DFP introduces tiered financial consequences for RSE failure. Another related, but non-financial, consequence is that an EDAM entity that fails the RSE when the market is unable to cure the insufficiency will be evaluated individually for the WEIM RSE rather than being evaluated jointly, as part of the pool, along with the passing EDAM BAAs. The DFP also includes a modified surcharge that will use the maximum of the Mid-C or Palo Verde day-ahead hub price for a 16-hour on-peak block of energy, for the entire multi-hour block, for each MW the BAA has been identified as being short. A credit will be applied in all hours that pass for the difference between a load weighted average of LMP’s within the BAA and the bilateral hourly price that the surcharge is based upon for each hour. In addition, the proposal is to index the Tier 2 and Tier 3 multiplier prospectively for every daily failure during the retroactive 30-day period. For every additional failure over a rolling 30-day window, 1 percent will be added to the surcharge starting with the second failure.

With respect to downward insufficiency failure, the consequence will be an hourly penalty that preclude the failed EDAM BAA from profiting on the energy for which the EDAM market is providing an off-taker. While NV Energy supports a financial consequence for a downward resource sufficiency failure at this time, it recommends that CAISO review the necessity for a downward flexible ramping test and the requirement that is imposed.  Since downward flexibility does not pose the same risk as what is necessary to meet the upward uncertainty, NV Energy questions why the level of uncertainty for the downward requirement is symmetrical.  

To reiterate, NV Energy does not support a penalty price for an organized market that is developed from using a trading hub price from the bilateral market. Stakeholders and CAISO should consider a price that uses a percent of the day ahead LMP, in order to avoid the consequences resulting in inaccurate assumptions about the liquidity of the bilateral market following the construction of a Day Ahead Market and the Western Resource Adequacy Program. To be clear, NV Energy does support the use of financial penalties if a BAA fails a RSE but does not support the current proposed design of this penalty.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

The DFP proposes to test the EDAM footprint for WEIM resource sufficiency considering all day-ahead awards, imbalance reserves, and reliability capacity. Each participating BAA is expected to address any intra-day outages that render any of the capacity used to back EDAM schedules prior to the running of the WEIM RSE. CAISO would use a hybrid pooled methodology under which a portion of the diversity benefit will not be allocated; instead, it will be reflected as additional global procurement of imbalance reserves for the footprint to use as a whole. The market operator would have the ability to configure this quantity to provide the EDAM BAAs a collective mechanism to adjust imbalance reserve requirements dynamically to provide additional confidence and reliability above the stated 97.5 percentile upward procurement threshold or, if extreme levels of uncertainty do not materialize, to cover for intra-day changing system conditions. The DFP recognizes that this approach will reduce economic benefits due to increased EDAM RSE showing requirements.

It is NV Energy’s understanding that this configurable parameter, to procure additional imbalance reserve reducing or eliminating the diversity benefit, will have bounds defined in a Business Practice Manual (BPM) but will provide the CAISO operators the discretion to change the parameter within the defined bounds. NV Energy does not support this proposal to procure additional supply beyond the amount that will be procured for the imbalance reserve product. The pool is expected to cure outages, derates, or supply shortfalls that occur prior to real-time, but will also have access to this additional supply that will be procured in day ahead above what is needed for the footprint to meet a P95 level of uncertainty while also carrying reserves to meet their own individual needs. This proposal seems excessive and costly to customers. If supply is already procured to meet all the uncertainty (P95 plus individual BAA contingency and regulating reserves) that occurs from Day-Ahead to Real-Time, then what could this additional amount be used to cure? Furthermore, NV Energy does not support a proposal to give the CAISO operators additional discretion to procure additional reserves for the market footprint or to establish the bounds in a BPM. This proposal will have impacts to market prices and NV Energy does not believe that CAISO has provided any justification to procure this additional uncertainty. 

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

The DFP proposes to introduce a net EDAM export transfer constraint into the market that permits all supply to be offered into the market while allowing the market to manage the amount of net export transfers supported by supply in the EDAM BAA. The net EDAM export transfer constraint would help remedy the asymmetry in the CAISO BAA arising from the resource adequacy must offer obligation. The constraint would be made available, on a voluntary basis to all EDAM BAAs that find it beneficial. The constraint would enable BAAs to offer supply in excess of their RSE obligation into the market and, through the constraint, manage how much internal supply is available to support export transfers out of the BAA on a net basis. The design and formulation of the net EDAM export transfer constraint is discussed further below.

As noted in response to question 4 above, NV Energy supports the consideration of a net EDAM transfer export limit constraint. The DFP notes that because the constraint is optional, an EDAM BAA that wants to use the net EDAM export transfer constraint within the market must (1) indicate its intent to use the constraint to the ISO and (2) describe either in its OATT or business practice manuals (a) the formulation for deriving the confidence factor applicable to non-RSE eligible bid in supply and (b) factors/criteria for deriving the additional margin that further reduces the constraint limit.

One issue that is not discussed in the DFP is how would the constraint be applied. Is the constraint applied only to the merchant arm of the EDAM Entity or could it be applied to third-party resources in the EDAM Entity BAA? The later ability is consistent with the OATT right to redispatch third-party designated network resources, but more detail is necessary regarding the application of the constraint.

In addition, NV Energy would like CAISO to consider a RUC run with the transfers locked between each BAA while counting the transfers that occurred in the IFM. This proposal might also be beneficial considering the CAISO BAA will be the only area that includes convergence bidding. It is our understanding that there are concerns with the current RUC proposal and the California Resource Adequacy program about the potential for resource adequacy supply being used to support the need of other EDAM participants.  NV Energy shares this concern and believes that an isolated RUC run may resolve the concerns. 

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

No additional comments.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

No additional comments.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

The DFP continues to support extending the EIM market power mitigation practices to the EDAM and note that any necessary adjustments to those practices are being discussed in the Price Formation Enhancements initiative. NV Energy supports this approach but highlights that there has been limited progress to date on that initiative.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

In the Revised Straw Proposal, CAISO included a two-year transition period before convergence bidding would become mandatory for an EDAM Entity. The CAISO proposed the transition to convergence bidding after one year; however, the EDAM Entity could either opt in for convergence bidding in their area at that time or select an additional year of transition. NV Energy opposed this prescriptive requirement which invites financial speculation into the transmission providers’ system and which could have a significant adverse effect on what have been fixed, predictable transmission costs under the OATT.

Th DFP is even worse - mandating either immediate implementation of convergence bidding at the start of EDAM participation or the election of a one-year transition period. NV Energy strongly objects to this approach. It is important to recognize that EDAM is not the same as joining CAISO. It is a hybrid of traditional OATT service and the ability to enhance economy energy transactions. OATT customers value certainty in their pricing arrangements. Significant, unanticipated uplifts may challenge any EDAM benefit proposition.

The CAISO uses convergence bidding as a means to reduce the incentive to over- or under-schedule demand. In contrast, the OATT requires customers to meet their forecasts or face penalties. EDAM reinforces the OATT paradigm by,

 

[i]ntroduce[ing] a resource sufficiency evaluation that evaluates each BAA and determines whether it has sufficient supply to meet its forecasted demand, uncertainty requirement, and ancillary services requirements. This supply is then made available to the market and optimally committed day ahead, resulting in transfers between EDAM BAAs.

There is no discussion as to why potential EDAM Entities would have the same challenges with price convergence that the CAISO does. Under the OATT, the issue of over or under scheduling can be addressed by requiring customers to come forward with resources to meet the forecast. This is what is done today in the EIM with the balanced schedule requirement that is then rolled into the EIM Entity base schedule. In order to appropriately allocate resource sufficiency and imbalance reserves, it is likely that OATT customers in EDAM will need to meet a planning reserve margin in addition to their forecasted amount.

The CAISO has stated that by using offsetting virtual supply and demand bids market participants can hedge congestion costs or earn revenues associated with differences in congestion between different points within the CAISO system by placing virtual demand and supply bids at different locations during the same hour. In EDAM, however, transmission customers should receive the same or better protection if the EDAM transfer revenue and congestion revenue is used directly to hold OATT customer harmless and congestion associated with use of their OATT intra-day rights. In other words, the market design is addressing this needed protection for all OATT customers on an equal basis without the use of convergence bids that allow not only the OATT customers themselves, but also third parties to engaging in the virtual bidding activity. Simply stated, the OATT construct is not CAISO transmission service. The transmission provider is still providing the service of moving resources to loads at a Commission-approved fixed price.

In comments to the April 28th Straw Proposal, NV Energy noted that if there is a pattern of price differences, virtual bidders can reap substantial profits which are paid for as an uplift by loads, and that CAISO has had to suspend convergence bidding under stressed system conditions because, “when the system is as tight as it was during [the August 2020] heat wave, convergence bids can allow for a day-ahead market that is not supportable by actual available resources and system conditions.”[1] Of course, CAISO is both the market operator and a BAA, and can take the market action to protect its own BAA. EIM Entities that choose to participate in EDAM would maintain their BAA responsibilities but would lack the ability to suspend convergence bidding if operational challenges arose unless that functionality was added to the CAISO Tariff.

Moreover, the CAISO does not offer convergence bidding at its interties. Based on data provided by CAISO, FERC found that “the overall impact of implementing the previously accepted tariff provisions establishing convergence bidding at the interties would result in decreased economic efficiency, and, therefore, would fail to provide the desired benefits of both price convergence and improved market efficiency.”[2] With no data on EDAM operations, with the potential for significant changes in new market designs and new market participants, it is unnecessary to make a commitment to  implement convergence bidding in a non-CAISO BAA participating in EDAM.

The DFP maintains that a one-year transition period “protects entities from potential unintended financial impacts, recognizing that EDAM entities may need additional time to gain experience in the day-ahead market prior to enabling convergence bidding,” and pledges that the CAISO will monitor the market’s performance and stands ready to engage with stakeholders to adjust this framework as necessary. These statements promising some potential prospective action after a prolonged stakeholder process fail to provide sufficient protection for the EDAM Entities customers. The CAISO cannot retroactively implement just and reasonable prices after the damage is done. CAISO customers paid approximately $58.6 million in uplift costs in the 10-month period when congestion bidding was permitted on the interties.[3]

NV Energy notes that when CAISO implemented convergence bidding in its own BAA, it imposed position limits on potential convergence bidding entities. In the filing letter in Docket No. ER10-1559, CAISO expressed a concern “about the potential for a new market element to create opportunities for market manipulation and unjust and unreasonable rates” and “limiting the megawatt volume of virtual bids that any one scheduling coordinator can submit at an individual node or intertie…will reduce the harmful effect that participant can have on the entire market.”  Indeed, FERC has recognized,

 

that at the start of convergence bidding, an additional safety net may be appropriate to prevent unforeseen and unintended market outcomes that might come about because market participants lack experience in the new convergence bidding market. Moreover, this lack of experience could result in illiquidity at certain nodes at the outset of convergence bidding, which in turn could lead to distorted market outcomes.[4]

NV Energy continues to maintain that whether to support convergence bidding within a BAA should be the choice of the transmission provider and their OATT customers. These customers should not face exposure from financial speculators who can create substantial uplift costs that have the potential to dimmish potential EDAM benefits. As an alternative, NV Energy has indicated a willingness to support initiating a stakeholder process to consider the specific issue of convergence bidding in the EDAM after two years of EDAM operation. That real-world experience and pricing data could better inform consideration of the issue rather than an unsupported assumption that it will be a benefit in a hybrid market with different footprints for day-ahead and real-time with the continuation of the EIM. Also missing from the DFP is a discussion of the settlement implications of convergence bidding and what EDAM and EIM uplifts and other charges will be allocable to these participants.

 


[1]           https://www.caiso.com/Documents/Aug14-15-StakeholderQandA.pdf. The CAISO determined that the presence of convergence bids contributed to supporting schedules that could not ultimately be honored in the real-time market. The CAISO determined that preventing the convergence bids from facilitating schedules that were not reliable provided the operators with fewer challenges in an already significantly constrained environment. The CAISO concluded it was better that the neighboring balancing authority areas know in advance instead of being in a challenging condition in real-time to serve their load having relied on unsupported exports, rather than first allowing the day-ahead market to schedule their export and then have to curtail it after it had been scheduled.

[2] California. Indep. Sys. Operator Corp., 152 FERC ¶ 61,234, at P 43 (2015).

[3] Cal. Indep. Sys. Operator Corp., 143 FERC ¶ 61,087 (2010) at P. 30.

[4] Cal. Indep. Sys. Operator Corp., 130 FERC ¶ 61,122 (2010) at P. 55.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

The DFP extends the EIM model of external resource participation to the EDAM. Source-specific supply associated with pseudo-tied and dynamically scheduled resources can economically bid and self-schedule at the EDAM footprint boundary interties. Non-source specific supply (non-pseudo, non-dynamic) located outside of the EDAM footprint that is contracted with an EDAM Entity (or a load serving entity located within the BAA) can continue to be self-scheduled at the EDAM footprint boundary interties. In addition, the DFP permits off-system network resources designated under an EDAM Entity’s OATT to economically bid at the EDAM entity’s interties. NV Energy supports the proposed framework for external resource participation.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

The DFP extends the EIM GHG accounting framework – the resource specific approach – to the EDAM with enhancements that seek to balance market efficiency, with the goal of limiting secondary dispatch. As indicated in our comments on the Revised Straw Proposal, NV Energy supports this approach.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

The purpose of a GHG counterfactual is to establish a baseline to determine what dispatch would have occurred in the non-GHG regulation area without offers to serve demand in GHG regulation areas. In the EIM, the counterfactual is the self-submitted base schedule. The CAISO limits GHG attributions to the lower of (a) the GHG bid capacity, (b) the resource’s optimal dispatch, and (c) the positive difference between the highest energy bid capacity and the resource’s base schedule. Because there are no base schedules in EDAM, the DFP proposes to leverage a special market run in the day-ahead market processes before the actual market run, solely to calculate a GHG counterfactual (“GHG reference pass”). NV Energy supports CAISO’s proposal to utilize a GHG reference pass as the GHG counterfactual. Additionally, NV Energy appreciates the additional explanation and details that CAISO provided for the proposed GHG solution.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

CAISO has proposed to implement a net export constraint as a measure to limit the secondary dispatch that occurs. NV Energy supports the use of this constraint to limit the secondary dispatch and supports the proposal to remove the constraint with a resource sufficiency failure. Market constraints that are utilized for emission accounting or attribution should not have an impact on reliability. 

There are still discussions on the additional steps that could be taken to mitigate and reduce secondary dispatch. It may be helpful for stakeholders to see examples that secondary dispatch will occur no matter the GHG design. There might be design choices that limit secondary dispatch, however, as CAISO clearly indicated in the November 14, 2022, stakeholder call that there are trade-offs. NV Energy is very appreciative that CAISO took the time to walk through examples and explain the reason why utilizing a dynamic constraint (Day Ahead schedule) rather than the upper economic limit may result in uneconomic outcomes. CAISO explained that a dynamic constraint could introduce congestion costs into the GHG marginal LMP or result in LMPs being under the generation bid-in cost resulting in under recovery. After reviewing this material, NV Energy supports the CAISO’s proposal to use the upper economic limit instead of the energy schedule. To be clear, NV Energy will not support a market design that may limit the secondary dispatch but will create areas that increase the need for bid cost recovery or other market pricing impacts. In principle, market designs to support state GHG policies should not have a negative impact to reliability or harm the economic benefits for participants located outside that GHG region.    

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

No comment.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

Transfer revenue represents the separation in the marginal energy costs between two participating BAAs when the scheduling limit is reached. The proposed design continues to reflect 50:50 sharing of transfer revenues accruing at the interfaces between participating BAAs, including the CAISO. 

Congestion revenue accrues when internal transmission path constraints or limits are reached, creating a separation in the marginal congestion component of the locational marginal price (LMP). The DFP continues to allocate congestion revenue that accrues when internal transmission system constraints bind, including modeled intertie constraints, solely to the participating BAA where the constraint originated.

NV Energy supports the proposed allocation of transfer and congestion revenue. As we have often stated throughout the EDAM stakeholder process, this revenue would be used to mitigate cost exposure from OATT customers exercising their existing right to modify intra-day schedules. Any shortfall or excess would be allocated to Measured Demand and would not be retained by the transmission provider.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

No comments at this time.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

No comments at this time.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:
  1. Gas Nominations and Participation by Use-Limited Thermal Resources

Gas nominations for the following day typically occur prior to 11:30 a.m., but the results of the day-ahead market post around 1:00 p.m. The DFP notes this can result in market participants having to make decisions regarding day-ahead gas nominations without the benefit of resource schedules for the next day and require market participants to engage in additional intra-day gas trading. The DFP maintains that, “[n]otwithstanding this complication, an entity is expected to perform in real time consistent with its day-ahead market awards” and states “[e]ntities currently participating in the ISO’s day-ahead market have successfully navigated similar challenges caused by these different timelines through internal procedural adjustments.”

As noted in the comments of Arizona Public Service to the Revised Straw Proposal, challenges surrounding gas pipeline constraints in the Desert Southwest may be different than current CAISO DAM participants face as the pipelines supplying a large amount of gas generation outside of California may have less flexibility from storage and tighter operating capacities that lead to more frequent utilization of strained or critical operating conditions that expose gas shippers to financial or physical penalties for deviations from scheduled takes. In addition, the Desert Southwest utilities may have different structures and lack a large base of gas customers with whom to share transportation costs.

NV Energy has previously stated concerns over gas management are heightened by the restrictions placed on commitment costs. The CAISO is the only ISO/RTO that does not allow market-based commitment costs bids subject to market power mitigation.[1] The existing commitment cost bid caps do not consider the value to the BAA which means that certain use-limited, gas-fired peaking units could be cycled at unacceptable rates depleting the allowed number of starts in a manner that would render the units unavailable for their primary purpose – to serve native load customers at critical times.

Currently, the use limited opportunity cost model utilizes the entire limitation for market use rather than removing a certain amount of the limitation to be utilized for Ancillary Services. The current design results in the lowest possible opportunity cost for the benefit of the market without considering the potential reliance of the resource to meet the BAA Ancillary Service needs. Therefore, the current market design is unworkable for the EIM or EDAM, which do not have an Ancillary Service market. If a resource located outside of CAISO serving a different BAA runs into the permitted limitation, then the BAA has lost a resource that simply cannot be replaced. This “missing” value is not a lost opportunity cost to the resource. Instead, the market is missing the value that these limitations have for the BAA to maintain a certain amount of the limitation to be used later in the year for reliability.

This is not a new issue. It has been a longstanding concern that has gotten lost in the need to address other higher priority issues with a potentially broader market impact. Given the increased scope of EDAM from the EIM, this issue can no longer be ignored for NV Energy to consider participation. CAISO must develop a revised commitment cost methodology that permits NV Energy to properly value the limited starts of these important peaking gas units.

  1. WRAP

The DFP recognizes at page 8 the importance of the interoperability between EDAM and the Western Resource Adequacy Program (WRAP). NV Energy agrees that as both EDAM and WRAP evolve, continued coordination will be necessary to ensure the two programs complement each other and maximize the value the programs provide for their participants.

  1. Interdependencies

In comments on the Draft Final Proposal, NV Energy noted the interdependencies between EDAM and a number of critical, ongoing CAISO initiatives: (1) the Day-Ahead Market Enhancements Initiative, (2) the Transmission Service and Market Scheduling Priorities Initiative, (3) EIM Resource Sufficiency Evaluation Enhancements, and (4) Price Formation Enhancements.

The parameters of any imbalance reserve product are still being considered in the longstanding day-ahead market initiative. Stakeholders are awaiting the revised wheel-through proposal. NV Energy notes that important issues related to price formation and system market power mitigation are being addressed in another stakeholder initiative but understands that there has been limited progress to date. In order to complete the EDAM design there needs to be resolution of the approaches to price formation and system market power. At some point the parallel paths must converge

 


[1] The CAISO’s survey of ISO/RTO bidding rules showed that all other ISO/RTOs support market-based bids for all components of the supply bid, including commitment costs, and apply mitigation to each component under various complex rules. PJM Interconnection, L.L.C. (PJM) uses a three-pivotal-supplier test to detect market power that is similar to the CAISO’s local market power mitigation test discussed below. However, PJM only limits commitment costs if a resource fails the test. PJM Open Access Transmission Tariff (OATT), Attachment K – Appendix, at section 6.4. The New York Independent System Operator, Inc. (NYISO), Midcontinent Independent System Operator, Inc. (MISO), ISO New England Inc. (ISO-NE), and Southwest Power Pool, Inc. (SPP) each use a conduct-and-impact market power test for commitment costs, and only potentially limit commitment costs if a supplier’s bids (i.e., its “conduct”) are above a certain cost threshold. ISONE Transmission, Markets and Services Tariff, Section III, Market Rule 1, at sections III.A.3- III.A.5; MISO Tariff, at sections 63-65; NYISO Market Administration and Control Area Services Tariff, at sections 23.1-23.3; SPP OATT, Attachment AF, at section 3.

Pacific Gas & Electric
Submitted 12/01/2022, 10:52 am

Contact

Todd Ryan (tmrt@pge.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

PG&E would like to offer our appreciation to the CAISO for continuing to lead an open and collaborative stakeholder process. We believe the CAISO has displayed a willingness to reflect stakeholder input in the proposed enhancements that recognizes the evolving needs of the sophisticated programs that the various parties are responsible for adhering to. PG&E is confident that EDAM is moving in a direction that builds upon increasing regional coordination, supporting state policy goals, and meeting demand in a cost-effective manner.

PG&E would like to start by acknowledging areas of positive progress in the Revised Straw Proposal. These enhancements build upon the stakeholder input requesting additional detail and incorporating improvements proposed by the initiative stakeholders. The areas of improvement are summarized as follows:

  • Tiered Consequences in the RSE. Recent proposals for EDAM did not distinguish between a one-megawatt and a one-gigawatt failure in the Day-Ahead Resource Sufficiency Evaluation. PG&E is encouraged that the Draft Final Proposal[1] has tiered consequences for deficiencies in the resource sufficiency evaluation.
  • Net Export Transfer Limit. Recent proposals have recognized the asymmetry between the CISO and other BAAs; specifically, that all other BAAs can provide supply above the RSE requirement but are not compelled to offer this capacity into the market. The CISO BAA did not have a mechanism to determine this type of participation in an equivalent manner. The Draft Final proposal includes a net-export transfer limit that provides this same functionality and creates a level playing field.
  • Alignment with other Issues. In previous comments, we emphasized the importance of alignment with other related initiatives.[2] PG&E notes that there has been significant progress in aligning EDAM with these initiatives including the cure mechanisms between EDAM and WEIM RSE Enhancements; and the consistency between EDAM and DAME’s proposal for net-export transfer limit.

 

PG&E appreciates the positive progress that we have achieved, and we look forward to contributing to the overall design.  The first section of our comments will provide insight into what elements PG&E supports, which have concerns, and which need further clarification. Additionally, the latter section highlights that the success and risks of EDAM are dependent on other concurrent CAISO initiatives.

 


[1] http://www.caiso.com/InitiativeDocuments/DraftFinalProposal-ExtendedDay-AheadMarket.pdf

[2] E.g., RSE Enhancements, DAME, and Transmission Service.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

Please see attached comments

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

Please see attached comments

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Please see attached comments

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

Please see attached comments

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

Please see attached comments

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

Please see attached comments

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

Please see attached comments

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

Please see attached comments

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

Please see attached comments

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

Please see attached comments

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

Please see attached comments

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

Please see attached comments

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

Please see attached comments

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

Please see attached comments

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

Please see attached comments

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

Please see attached comments

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

Please see attached comments

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

Please see attached comments

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

Please see attached comments

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

Please see attached comments

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

Please see attached comments

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

Please see attached comments

PacifiCorp
Submitted 11/22/2022, 03:18 pm

Contact

Nadia (Nadia.Wer@Pacificorp.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

PacifiCorp appreciates the refinements and clarifications the CAISO provided as part of the Draft Final Proposal in response to stakeholder comments. As put forth in the written proposal and various stakeholder calls, aside from a small number of suggestions included in our comments, PacifiCorp considers the EDAM design a workable market design for a first of its kind, incremental, day-ahead (DA) market. While we anticipate future work streams focused on tariff development, business practice manuals and future implementation to elucidate several additional issues to be addressed, PacifiCorp is confident that that they can be solved. PacifiCorp appreciates the CAISO staff as well as all the parties who contributed to the thoughtful, roust, and well-considered stakeholder process.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

PacifiCorp supports the proposed voluntary participation model as it provides an easy entry and exit process along with useful transitional measures. The proposed extension of the transitional pricing measure and price correction time horizons are important features to allow interested entities to manage the risk associated with joining EDAM.

Regarding the proposed changes in the EDAM resource participation model, PacifiCorp appreciates the CAISO adding an option for PURPA resources subject to regulatory must-take requirements or with special contractual provisions regulated by state commission to participate in EDAM without requiring contractual changes such as contracts for differences. The CAISO should be mindful that the transition from physical PPA to a financial/contract for differences model is difficult, if not impossible, in many circumstances given the interplay of regulatory requirements and the various interested parties including third party investors with consent rights to contract changes. In addition to PURPA resources, certain PPAs of an older vintage may not include curtailment rights, thus rendering them must-take resource even though they do not meet the PURPA or regulatory must-take requirements. PacifiCorp requests the CAISO consider extending the same must-take treatment to PPA contracts that do not include curtailment rights.

On a matter of principle, PacifiCorp considers the requirement for independent generators to pay their fair share when wheeling power within or out of the BAA they are located in as vital. Consequently, PacifiCorp appreciates the CAISO’s latest proposal to require independent generators located within a BAA to procure firm transmission to get to the border. However, in recognition of the potential challenges and supply shortages of long-term firm point-to-point transmission (as specified in the Draft Final Proposal), PacifiCorp suggests the CAISO consider relaxing the requirement of long-term firm transmission to simple firm transmission of any duration. Additionally, PacifiCorp supports the proposal included in the recent EDAM workshop that an independent generator pay the short-term firm transmission rate for any dispatch above its existing transmission rights. To incentivize transmission procurement, this after-the-fact transmission purchase would also apply to any applicable incremental dispatch in EIM.

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

The Draft Final Proposal introduces two key refinements. First, the introduction of a net export transfer constraint which is made voluntarily available to EDAM BAAs, allowing them to determine how much of their supply can support transfers out of their BAA. We support the export transfer constraint as a tool to provide additional re-assurance and comfort to entities interested in preserving an extra amount of supply that cannot be transferred in the market. While the overall market efficiency arguably increases with allowing the market to optimize across all resources, PacifiCorp considers this tool useful in allowing new entities the ability to establish comfort with the new market while also ensuring additional control over its own reliability by actively managing its excess supply position.

Second, while the Draft Final Proposal maintains the idea of equal priority to load in stressed conditions, it no longer includes the requirement to apply lower transfer priority to an entity that has failed the RSE. While PacifiCorp maintains its view that strong RSE failure consequences are a necessary condition for a successful market straddling two RA frameworks, the inherent operational complications related to the potential implementation of lower transfer priorities result in PacifiCorp supporting the revised specification.

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

PacifiCorp acknowledges the CAISO’s work on continuing to refine the treatment of transmission rights through the “buckets” and “pathways” model. We appreciate the CAISO’s responsiveness to stakeholder questions and concerns considering the challenges inherent in making a full day-ahead market co-exist with the OATT in this manner.

The Draft Final Proposal clarifies that “ETC/TOR” treatment is available to all existing transmission rights under the OATT, including both NITS customers and point-to-point customers. As we understand the Draft Final Proposal, this treatment will permit those existing OATT customers to use self-schedule functionality to direct its resources to its loads, which would exempt such customers from any congestion charges associated with its transmission usage. We further understand, however, that the EDAM will still clear such self-schedules through the market and an OATT customer will still pay, and be paid, the locational marginal price notwithstanding the use of a self-schedule. Stated another way, giving OATT customers ETC/TOR treatment for self-schedules associated with their OATT rights will exempt them from congestion charges (and congestion revenues) but will not take them entirely out of the market. In general, PacifiCorp believes the CAISO should offer this ETC/TOR treatment for OATT rights, at least in the initial roll-out of EDAM. In the long run, PacifiCorp is concerned that overuse of self-schedules may degrade the quality of market outcomes and, by exempting customers from congestion charges, may mute price signals that serve to inform capital investment infrastructure. Such overuse may also hinder the realization of the forecasted benefits of EDAM. Having said that, PacifiCorp believes this ETC/TOR treatment for self-schedules should be included in the final proposal because it may provide useful functionality as OATT customers transition to operating in the market features of EDAM.

Notwithstanding PacifiCorp’s support as explained above, we offer two additional comments.

First, PacifiCorp understands the CAISO has the functionality to similarly exempt OATT customer self-schedules from marginal losses as well as congestion. As the CAISO and other participating EDAM entities draft their respective tariff changes to implement EDAM, and as the interaction between EDAM and the OATT becomes clearer, exempting these self-schedules from marginal losses will need further consideration.

Second, there is an issue that must be considered for the proposed design to be implemented. The Draft Final Proposal understandably requires EDAM entities to register in the CAISO master file such OATT rights that will be granted ETC/TOR treatment. Point-to-point rights by their nature can effectively be registered in the master file since the quantity of service and contract path are matters of executed service agreements. Modeling NITS rights presents a unique challenge because NITS customers effectively use the entire network to deliver their Designated Network Resources to their Designated Network Loads under the OATT. These rights cannot always be modeled in the same way as point-to-point rights. While the NITS-on-OASIS platform has required utilities to distill NITS rights into quantifiable “scheduling rights” across specific paths that will facilitate this process, not all NITS rights are reflected in such scheduling rights. This will present a challenge to ensuring that historical OATT rights will have equitable access to ETC/TOR treatment. PacifiCorp does not suggest a change to the Draft Final Proposal on this point, but to emphasize that significant work will be required to bring this proposal to fruition.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

PacifiCorp supports the CAISO’s proposal of the historical transmission revenue recovery as outlined in the Draft Final Proposal.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

PacifiCorp understands from its review of the Draft Final Proposal and tariff framework that each EDAM entity will be expected to ensure all EDAM Transmission Service Providers in its BAA make available for use in the day-ahead market transmission capacity that is included in the EIM Transmission Service Information. It must be noted that there are third parties that own transmission facilities which are integrated into PacifiCorp’s two BAAs. If the participation of these entities cannot be secured, it will be necessary to determine how these facilities are treated in the EDAM design. Specifically, PacifiCorp understands that all relevant transmission facilities in its BAA must be modeled for the market to work correctly, so it may be necessary to grant ETC or TOR treatment to owners of transmission facilities within an EDAM BAA that do not authorize inclusion of those facilities in the EDAM. PacifiCorp encourages the CAISO to consider including that flexibility in the final proposal and ultimate tariff language.

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

PacifiCorp agrees with the proposed ability to have advisory runs prior to the binding run of the resource sufficiency evaluation at 10:00 a.m.

While not ideal, PacifiCorp appreciates the complications related to making the RSE a fully security constrained test. As such, we consider the CAISO’s current proposal workable with the hope of potentially re-addressing this issue in the future if initial market data indicates it is necessary. PacifiCorp agrees that locking VER and load forecasts at 9:00 a.m. will help allow entities the ability to hedge and ensure they pass the final 10:00 a.m. RSE test. In the last round of EDAM comments, PacifiCorp requested that the CAISO consider parallel operations of the RSE for a 6-month period to ensure performance as expected and appreciates the inclusion of this in the draft final proposal, although without an explicit length of time posed. In addition, PacifiCorp supports the proposed handling of forecasted demand, imbalance reserves, flexibility requirements, ancillary services, and reliability capacity, as well as demand response and VER forecast enforcement as described in section II.B.2 of the Draft Final Proposal.

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

To ensure the success of EDAM, it is imperative that BAAs come into the market resource sufficient. PacifiCorp supports the proposed tiered framework for failure consequences, with some clarifications, as we consider it a reasonable approach to address concerns regarding penitential de minimums failures while providing significant financial penalties for larger and/or repeated failures.

However, the CAISO should consider the following clarifications to the tiered framework. If the market is unable to meet demand, ancillary, services, and the upward imbalance reserve requirement for all EDAM BAAs, then the BAA that failed the RSE should no longer be included in the WEIM pool, regardless of the tier of the RSE failure. Additionally, Tier 3 currently allows for a BAA to cure 50% or more of its upward imbalance reserve requirement. PacifiCorp’s position is that leaving the amount an entity can cure through the market uncapped is not prudent, regardless of the market’s ability to meet the requirements of the footprint. Therefore, the CAISO should consider a cap on Tier 3, for example, 100% of the BAA’s upward imbalance reserve requirement, meaning an entity’s inability to meet demand cannot be cured through the market.

PacifiCorp further considers the proposed methodology for calculating the administrative surcharge, especially the introduction of the credit for hours where an entity did not fail, as principled and more appropriate than simply applying a 16-hour block price as previously proposed.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

PacifiCorp is supportive of the proposal to pool all EDAM entities who passed the EDAM RSE for the purpose of passing the WEIM RSE as this allows passing entities to benefit from the diversity benefit across the footprint. PacifiCorp also supports an EDAM entity being independently evaluated in the WEIM RSE in the event the day-ahead market cannot cure the EDAM RSE deficiency or the EDAM entity’s day-ahead deficiency is more than the capped amount that is allowed be cured in the market.

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

PacifiCorp supports the CAISO’s proposal to set up the net EDAM export transfer constraint as an hourly constraint within the IFM as well as making this feature optional for EDAM BAAs. While we appreciate the CAISO’s desire to motivate all BAAs to feel comfortable bidding in all supply into the market, PacifiCorp wants to caution that, at least upon initial launch, new EDAM entities may still enter the market conservatively with the expectation that as each EDAM entity gains experience and comfort with EDAM, behavior may change over time. The CAISO should also consider allowing participants the ability to use their Available Balancing Credit (ABC) in the RSE.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

PacifiCorp does not have any additional comments at this time.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

The CAISO is proposing to incorporate new products, as outlined in the DAME Initiative, that will aid the footprint when uncertainty arises and lower each participants imbalance reserve requirement as part of the overall diversity benefit derived from being an EDAM participant. PacifiCorp agrees that increased reliability is the common denominator and with that, incorporating imbalance reserve and reliability capacity products within the day-ahead timeframe is prudent to having a sustainable market design. Decreasing the number of out-of-market actions taken by the CAISO limits exposure to volatile prices that may materialize during the operational day versus in the day-ahead. PacifiCorp supports the proposed changes outlined in II.C.2 and II.C.3.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

PacifiCorp supports the BAA grouping methodology enhancement to the market power mitigation framework as proposed in the Price Formation Initiative. However, PacifiCorp requests that the CAISO allow participants to adjust their default energy bid (DEB) after each market run to reflect more accurate pricing. Additionally, PacifiCorp looks forward to further refinement of the methodology and requests the CAISO to address how they intend to monitor its performance after implementation.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

PacifiCorp supports the CAISO’s proposal for allowing EDAM entities the option of either participating in convergence bidding right at the start of joining EDAM or after the proposed yearly transition period.

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

PacifiCorp is generally supportive of the proposed treatment of external resource participation.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

PacifiCorp appreciates that stakeholders have respected the unique considerations of PacifiCorp, with two BAA footprints, as well as being a retail provider of load in six states with diverse and evolving clean energy policies. PacifiCorp continues to support the CAISO’s Draft Final Proposal to launch EDAM with the resource-specific methodology and its proposed modifications that reflect differing and evolving state policies.

The CAISO shared at its November 14 stakeholder meeting that it will evaluate the EDAM GHG design after its first year of implementation to assess whether enhancements or evolution is needed based on performance and regulatory updates. PacifiCorp is supportive of this iterative approach and for evolution of the GHG design without sacrificing expediency in the deployment of EDAM.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

PacifiCorp continues to support the CAISO’s proposal to use a GHG Reference Pass as the GHG counterfactual for measuring secondary dispatch.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

PacifiCorp recognizes the iterations the CAISO has gone through to evolve this measure for limiting secondary dispatch and supports the CAISO’s proposed modifications and clarifications on the net export constraint. Limiting the attributions to resources within a net-exporting BAA seems logical, given the complications discussed at the recent EDAM workshop, PacifiCorp would not be opposed to delaying the implementation of the constraint.

PacifiCorp looks forward to further engaging on the performance of this constraint, and other GHG topics, in future stakeholder workshops after the market has been implemented.

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

PacifiCorp does not have any additional comments at this time.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

PacifiCorp supports sharing accrued transfer revenues 50:50 when the constraint is at the intertie of two EDAM BAAs but not sharing the accrued transfer revenues when the constraint is internal to a specific EDAM BAA.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

PacifiCorp generally supports the provisions in section II.D.2. PacifiCorp appreciates the extension of the Draft Final Proposal extension of the WEIM Unaccounted for Energy election provisions to the EDAM BAA’s.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

PacifiCorp supports the details outlined in the Draft Final Proposal regarding the EDAM implementation and administration fees.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

PacifiCorp does not have any additional comments but would like to thank CAISO staff as well as all other stakeholders for their active engagement in developing the Draft Final Proposal. PacifiCorp looks forward to working to continue collaboration on refining the EDAM design.

Portland General Electric Company
Submitted 11/22/2022, 01:15 pm

Contact

Ryan Millard (ryan.millard@pgn.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

Portland General Electric Company (PGE) appreciates the opportunity to provide comments on the CAISO’s Extended Day Ahead Market (EDAM) Draft Final Proposal.   PGE would also like to acknowledge and extend our appreciation for the extraordinary level of effort and collaboration that CAISO staff has exhibited throughout the stakeholder process.  Ultimately, the CAISO’s commitment to balancing a variety of potentially competing interests and priorities has resulted in an initial market design offering that maintains the principles of voluntary participation, ensures low-cost entry and exit, respects many of the complex operational considerations of those operating under an Open Access Transmission Tariff (OATT) structure, and builds from the successes of the Energy Imbalance Market (EIM).  As such, PGE is generally supportive of the draft final proposal. 

Throughout the EDAM initiative, there has been a common understanding amongst stakeholders that this effort stems from a desire to capture potential incremental benefits through incremental changes that do not require revisions to state law or need to involve jurisdictional concerns and broader transmission planning and cost allocation challenges associated with a Regional Transmission Organization (RTO).  As such, the EDAM has been viewed by PGE as a unique, incremental solution (and has been assessed through this lens) that will require subsequent enhancements and refinements.  For instance, PGE recognizes that additional examination will be required as it relates to the interoperability of different Resource Adequacy programs and EDAM, RSE failure consequences and a more detailed operational understanding of how pooled BAAs are expected to cure those failures, and potential refinements to the modeling of GHG optimization and accounting to account for unique circumstances.  PGE encourages the CAISO to continue to work on these enhancements so that they can be considered early in the operations of the broader market offering and looks forward to participating in those discussions.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

PGE has no additional comment.  

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

PGE has no additional comment.  

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

PGE has no additional comment.  

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

PGE has no additional comment.  

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

PGE has no additional comment.  

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

PGE has no additional comment.  

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

PGE has no additional comment.  

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

PGE has no additional comment.  

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

PGE has no additional comment.  

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

PGE has no additional comment.  

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

PGE has no additional comment.  

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

PGE has no additional comment.  

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

PGE has no additional comment.  

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

PGE has no additional comment.  

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

PGE has no additional comment.  

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

PGE has no additional comment.  

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

PGE has no additional comment.  

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

PGE has no additional comment.  

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

PGE has no additional comment.  

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

PGE has no additional comment.  

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

PGE has no additional comment.  

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

PGE has no additional comment.  

Powerex
Submitted 11/22/2022, 04:52 pm

Contact

Powerex Trade Policy Team (pwx.reporting@powerex.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

Powerex submits the following comments on the CAISO’s October 31, 2022 Extended Day-Ahead Market Draft Final Proposal (“Draft Final Proposal”) and the discussion at the associated public workshops in this initiative.

The development of formal programs to unlock the large potential benefits of coordination across multi-state geographic footprints is critical to achieving a transition to a lower-carbon grid while maintaining reliability and keeping electricity affordable for ratepayers.  Multiple such programs are moving forward, including the Western Resource Adequacy Program (WRAP) focused on the forward planning timeframe, as well as the EDAM/EIM and Markets+ organized market platforms focused on the day-ahead and real-time timeframes. 

Powerex has actively participated in the EDAM stakeholder process for several years, as well as in the Markets+ development effort.  Powerex recently announced its decision to participate in Markets+ (and several additional entities have committed to fund the detailed development of that market).  At the same time, there are other entities that continue to focus on EDAM/EIM. While CAISO and SPP may each seek to emerge as “the” predominant organized market for much of the west, Powerex sees a future in which both Markets+ and EDAM/EIM each exist with a significant number of participants, with most of those entities also participating in WRAP.  Powerex fully supports this evolution for the west, as it believes every entity in the west must have the ability to choose the day-ahead and real-time organized market platform that provides the governance, market design, and resource mix (generation, transmission and load diversity) that is most beneficial to them and their ratepayers. 

Powerex’s comments reflect its perspective as an entity that will not participate in EDAM, but will continue to procure transmission service and transact with entities that may become EDAM participants.  In particular:

  • Powerex has invested in Firm OATT rights on numerous transmission service providers’ (TSP) systems in the west—including some TSPs that may elect to participate in EDAM—and seeks to ensure its ability to continue to use these Firm OATT rights to deliver supply under forward arrangements, including where such forward commitments are used by others to meet their WRAP forward showing obligations.
  • Powerex will continue to enter into arrangements to receive energy from other entities—including entities that may elect to participate in EDAM—and seeks to ensure that those entities will continue to be able to identify and use their physical capacity and OATT transmission service to support those commitments in the operational timeframe, ahead of any other uses.  This is particularly important to Powerex as it relates to the WRAP operational program obligations of those EDAM participants that are also in WRAP (i.e., to deliver on WRAP holdback obligations to Powerex and other non-EDAM WRAP participants).

Powerex is concerned that the Draft Final Proposal includes design elements that would unnecessarily interfere with the above activities, harming non-participants such as Powerex.

As WRAP, Markets+ and EDAM/EIM continue to move forward, it will be important that each of these regionalization efforts be designed to carefully maintain the value of firm transmission service under the OATT framework.  To achieve this, firm transmission customers must continue to have the ability to use their rights efficiently and effectively for the activities, programs, and markets of their choosing, consistent with the principles of open access and transmission reciprocity.

 

EDAM Must Not Create A New Transmission Blockade On Other Western TSP Systems

The Draft Final Proposal takes a highly aggressive approach to making transmission capability of EDAM entities available to support EDAM transfers.  The initial concept of EDAM was specifically designed to utilize only Firm transmission service that was either unsold by the TSP or that was affirmatively made available by the Firm transmission rights-holder.  The Draft Final Proposal goes far beyond this initial concept, to also include transmission capability already committed as Firm OATT rights, and where the customer has not voluntarily made that capacity available to EDAM, if the customer has not submitted a self-schedule to use those rights by 10 a.m. of the day prior to delivery (i.e., “unscheduled Firm” capability).  Although the Draft Final Proposal leaves open the possibility that the Firm transmission customer could still be permitted to self-schedule on their Firm rights after this new day-ahead scheduling deadline, it describes that use as a “late exercise” of those rights, that will only be allowed “if practicable”, and will be subject to congestion and other charges in EDAM or the EIM.  This means that transmission customers that invest in Firm OATT rights of a TSP that participates in EDAM will either face an outright prohibition on using their rights outside of EDAM after 10 a.m. of the day prior, or will be exposed to new and uncertain financial charges for doing so.    

This is highly problematic, and amounts to a dramatic claw back of the OATT firm rights that were sold, as there is no proposed framework for a transmission customer to “opt out” and choose to hold its Firm rights outside of EDAM. These new restrictions and/or financial charges will directly interfere with the ability of a transmission customer to rely on its Firm OATT rights to:

  1. Serve its own load through real-time;
  2. Satisfy its forward commitments to others (that entail deliveries scheduled in real-time), including forward sales used to meet WRAP forward showing obligations;
  3. Engage in real-time bilateral trading activities;
  4. Meet WRAP operational program delivery obligations through real-time;
  5. Deliver variable quantities, such as for the output of wind facilities, outside of the EDAM footprint; and
  6. Support participation in Markets+ (through the set aside of firm rights as Markets+ “ETSRs” on non-participating transmission service providers systems, similar to how the Western EIM has achieved the connectivity of its footprint using firm rights on non-participating transmission providers systems).

The Draft Final Proposal appears specifically designed to maximize the transmission capability available to EDAM by:

  1. Enabling EDAM to use transmission capacity that has already been sold to other customers, but that has not been voluntarily provided by such customers to EDAM; and
  2. Clawing back the ability of transmission customers to rely on their Firm OATT rights for deliveries outside of EDAM after 10 a.m. on the day prior.

As stated above, Powerex is fully supportive of EDAM and other organized markets developing and growing in the west, but that growth is properly achieved by making EDAM’s governance and market design more attractive to a critical mass than the alternative, not by depriving entities of any other choice through EDAM rules that can effectively be described as a real-time “blockade” on Firm transmission use outside of EDAM.

 

All TSPs Should Provide A Mechanism For Transmission Customers That Intend To Use Firm OATT Rights Outside Of EDAM

Powerex anticipates that the likely outcome of the proposed EDAM transmission approach will be that customers that hold OATT rights on transmission systems participating in EDAM will still use these rights for all of their intended purposes, including WRAP and Markets+ participation, but they will now need to schedule the use of their rights prior to the 10 a.m. day-ahead deadline, as inflexible hourly “blocks”.  This will result in transmission use that is inflexible and less efficient than if delivery schedules were shaped to the needs of the destination market or program.  And if this is the framework that results in the west from EDAM’s transmission approach, it is not inconceivable that transmission rights of TSPs that participate in Markets+ may face similarly inefficient scheduling restrictions to being used in EDAM.  The net result is that a substantial amount of transmission capability across the west will be scheduled inefficiently and will be unavailable to be optimized by either EDAM or Markets+.  This will also greatly erode the value of Firm transmission service, ultimately reducing third party investments in OATT transmission service providers systems, and shifting transmission costs onto native load customers.

A more efficient outcome would be for TSPs to ensure that their Firm transmission customers have the full ability to elect to use those OATT rights to connect to their desired markets.  Bonneville has been the standard-bearer for this supportive approach.  Long before Bonneville decided to participate in the Western EIM, it dedicated significant technical and staff resources to work closely with transmission customers that held Firm OATT rights on Bonneville’s system and that sought to use those rights to enable EIM participation.  This reflects Bonneville’s commitment to maintaining the value proposition of investing in Bonneville Firm transmission service, which means enabling transmission customers to determine how best to utilize those transmission rights.

Powerex believes a workable approach to enabling efficient optimization of transmission capability and supporting incentives for continued investment in OATT transmission service would be for all TSPs to allow rights-holders to elect to have their rights remain “out” of the organized market platform that the respective TSP has elected to participate in, in order to enable the customer’s participation in a different organized market or operational program, such as WRAP.  Reasonable limitations may be appropriate regarding how frequently this election can be changed, and on the type and duration of transmission rights able to make this election.  For instance, the election may be available only on long-term Firm rights, and may be required to be made for one year at a time.  This framework should also be reciprocal; that is, TSPs that join EDAM will provide their rights-holders the ability to set aside OATT rights to support participation in Markets+, while TSPs that join Markets+ will provide their rights-holders the ability to set aside OATT rights to support participation in EDAM.  The desirable result of such an approach would be to increase the ability of both organized markets to optimize transmission capability, and to make transmission rights equally able to support customers’ participation in either organized market.

 

EDAM Must Enable EDAM Participants To Designate Supply And OATT Transmission In Support Of Commitments With Higher Priority Than EDAM Transfers

From the outset it has been acknowledged that EDAM is not a resource adequacy program, will not enforce a common resource adequacy requirement, and will not change the resource planning responsibilities and arrangements of each entity.  EDAM may therefore include entities that are very differently situated, from a resource adequacy perspective. While it would be reasonable to assume that a majority of external EDAM participants will be participating in WRAP, any evaluation of the Draft Final Proposal must be grounded in the clear recognition that the largest participant in EDAM—the CAISO BAA—may very well continue to be short several thousand megawatts during critical hours, and will be needing to obtain supply from other EDAM participants to fill this deficit[1]

Unfortunately, the current EDAM design does not overcome this fundamental resource adequacy challenge. Rather than provide incentives for all participants to address their capacity needs in the forward timeframe, the EDAM Resource Sufficiency Evaluation (RSE) expressly permits entities that are short of sufficient capacity to financially “cure” their deficiency. This “pay your way out” approach does nothing to resolve the CAISO BAA’s physical shortfall and will necessarily result in less physical supply being made available to the EDAM footprint relative to a framework that actually ensures each entity is resource sufficient in advance. Simply put, the CAISO BAA’s chronic resource deficit will be a drain on the supply resources of other EDAM participants, as it has been in the Western EIM.

Given the CAISO BAA’s resource adequacy challenges, the expectation that EDAM transfers are curtailed pro-rata with an entity’s own load, and that participation in EDAM is likely to include WRAP members that have obligations to entities that are not EDAM participants, this raises a critical question: what mechanism will enable an EDAM participant to ensure that the supply and OATT transmission it is required to make available under the WRAP operational program remains available to be exported outside the EDAM footprint, and is not used instead to support transfers to (deficient) entities within EDAM? 

A clear mechanism is necessary for EDAM participants to set aside the additional supply and OATT transmission to fulfill their obligations under the WRAP Operation Program, otherwise those commitments will have the same priority as EDAM transfers to entities that are not WRAP participants (including the CAISO BAA).

The Draft Final Proposal appears to lack a clear mechanism to ensure that EDAM participants can set aside the additional supply and OATT transmission to fulfill their obligations under the WRAP operation program.  In particular, it is unclear how an EDAM participant could “set aside” supply and OATT transmission to meet its WRAP Operational Program holdback requirement. By failing to provide a clear and robust mechanism for entities that participate in EDAM to satisfy their obligations to WRAP, the Draft Final Proposal interferes with entities’ ability to credibly participate in WRAP, potentially undermining the ability of that program to fully realize capacity diversity savings for ratepayers in the west.

To be clear, Powerex has no objection to a WRAP member participating in EDAM and electing for its own load to have the same priority as transfer to other EDAM entities, including the CAISO BAA.  But Powerex strenuously objects to the erosion of that entity’s commitments to WRAP members that do not participate in EDAM.  Quite simply, such commitments must have higher priority than EDAM transfers, with such delivery obligations remaining intact during conditions when EDAM transfers are curtailed, including when this results in pro-rata EDAM load curtailments.

There is no need for EDAM to be designed in a manner that prevents entities from meeting their commitments and obligations under WRAP.  In prior working groups and stakeholder meetings, Powerex and other stakeholders have described a mechanism through which each EDAM participant can designate identified supply resources and high-quality OATT transmission that supports high priority commitments to other BAAs, including BAAs outside the EDAM footprint.  This supply and transmission can be fully “carved out” of EDAM altogether, with the market operating as if the supply and transmission were not available in the optimization.  A potential alternative would be to enable EDAM to optimize the supply and transmission, but assign the very highest priority to the designated load being served by those arrangements in the event there is either insufficient aggregate supply or transmission capability to meet that commitment as well as demand in the EDAM footprint. 

 


[1] California’s RA program has a long history of leaving the CAISO BAA significantly short of the real physical resources needed to reliably serve load during critical hours.  CAISO as well as the CPUC have repeatedly projected that the CAISO BAA has a supply deficit of 5,000 MW or more.   The resource shortfall resulting from the significant gaps in California’s RA program are a large part of the reason why the CAISO BAA routinely requires imports from the Western EIM to maintain reliability, and has entered energy emergencies on numerous occasions even while receiving thousands of megawatts of supply from the rest of the EIM.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

See comments above.  

Powerex’s comments are also available at Extended Day-Ahead Market Draft Final Proposal Comments

Public Generating Pool
Submitted 11/23/2022, 03:05 pm

Contact

Sibyl Geiselman (sgeiselman@publicgeneratingpool.com)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

PGP appreciates the CAISO and stakeholders continued efforts to develop a durable and fair proposal for the Extended Day Ahead Market (EDAM). Given the substantive and evolving changes in the most recent draft, PGP has concerns about the current timeline and the release of the Final Proposal without further opportunity for feedback from the stakeholders, particularly on concepts that have been newly introduced in the most recent draft or have language in the proposal that does not align with discussions from the meeting on November 14th. Considering the intersection with other stakeholder initiatives that are in process, and the general lack of direct reference to these initiatives within the EDAM proposal, PGP recommends that the next draft works to address linkages more directly and clearly assess outstanding disconnects between the EDAM design and related market processes that are under revision.

In general, PGP supports the Balancing Authority Area (BAA) voluntary participation framework as it aligns Open Access Transmission Tariff (OATT) frameworks and locally funded transmission systems with a broader market participation framework and optimization. This said, there are multiple areas in the proposal where the BAA is referenced as if it automatically aligns with the Transmission Service Provider (TSP), when this is not always the case. Careful consideration of these situations will be required to avoid cross-subsidization issues.

Other general concerns are associated with the misalignment with resource adequacy programs. These programs are arguably outside of the scope of the EDAM design but have significant implications for how various parties might be incentivized to participate in and/or use, the market. If EDAM enables the avoidance of long-term resource procurement, it undermines the fairness and durability of the market design. PGP notes that most potential non-CAISO EDAM Entities are currently non-binding participants in the newly formed Western Resource Adequacy Program (WRAP), but will be transitioning to the binding phase of the program as EDAM begins to go live. While this program is non-binding would be an ideal time for continued analysis on the benefits of a broader footprint, and if maintaining an adequate reliability standard to incentivize participation from a broader footprint is sufficient incentive, economically and otherwise, to drive appropriate RA procurement to this regional standard. Reliability benefits and capacity savings from a broader market footprint are a large portion of the potential benefits of an expanded market, many of which have the potential to accrue to CA ratepayers, and they are at risk if market participants cannot count on each other to bring the appropriate share of resources to the market within the planning horizon, not just the operational time frame. Recent events in CAISO and the significant need for imports even when CA was clearly using all of its available resources, seem to indicate that the existing CAISO footprint suffers from a lack of adequate supply, and begs the question as to what needs to be fixed to make it adequate in time for regional participation in a shared market. All analysis done on RA programs and on the benefits of an extended market footprint indicate that a broader footprint with shared adequacy standards and the ability to fully unlock the diversity inherent in a broader footprint have the potential to provide substantive benefits to all participants, and those benefits are at risk if a regional adequacy standard is not upheld. Potential EDAM entities need to continue to evaluate the benefits that may be at risk without a footprint-wide adequacy program and maintain the objective of encouraging long-term resource adequacy in all aspects of market design.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

  PGP had concerns with the original proposal using a backward-looking calculation for the historical transmission revenue recovery. Given the anticipation of continued declines in bilateral trading and likely declines in secondary transmission sales, use of a historical metric on a system use that is going to decline will by its nature will evolve to a declining funding of the transmission system. Without other mechanisms to encourage long-term funding of the transmission system, and/or adequate compensation for transmission owning entities in-lieu of resale revenues, this has the potential to create a downward trend in funding for the OATT  transmission system. Lack of an organized market with a structured method for evaluating new transmission build further exacerbates this problem.

The newly proposed transmission requirement presented in section II.A.1.c) and a default resolution to the most granular rate available is a solution that will support long term transmission funding and limit free ridership, but also enable resources to balance the cost of transmission of different types to optimize their assets. One of the benefits of EDAM is reducing the need for pancaked transmission rates, not eliminating transmission charges altogether, and that for generators who would like to market to different EDAM entities this is still a significant improvement upon the status-quo, and is a worthy attempt to bring some important elements of the OATT framework into the market construct with acknowledgement that this is not an RTO. This default rate, while not a replacement for transmission resale, incentivizes the purchase of transmission and the funding of the OATT systems. This option enables non-contracted resources to fully participate even when they are unable to procure long-term transmission, which is particularly relevant for new renewable generation that is expected to come online in the coming years.

Upon discussions with CAISO, it was noted that there may be some unique circumstances that need to be addressed, namely relating to BAs that are nested within another potential EDAM participant footprint, and therefore would not have access to the market without a wheel-through. This could result in a cost shift from the nested BAA to its “host” TSP, and should be addressed with clarifying language in the final proposal, and an acknowledgement that TSP and BA footprints do not always align.

Other concerns that need to be addressed in the final language include clarifying the appropriate default rate. While the daily rate was proposed on the November 14th call, follow up conversations indicated that this would revert to the lowest granularity firm rate. PGP notes that most new resources are expected to be lower Net Capacity Factor (NCF) renewables, indicating that an hourly rate may be more appropriate where it is available. There are some differences in the hourly rates per the varying footprints that exist today, indicating this should not be an issue or change vs the current market, and likely the more important difference would be if there was a difference in granularity of the default rate, with some defaulting to Daily and other to Hourly. The monthly rate seemed overly onerous to many stakeholders, but further discussion may be required to determine which more granular rate is most appropriate.  Upon a cursory review of the most granular transmission available, PGP notes that some entities classify the hourly as Firm or Non-Firm (for the same rate, given this is as-available) and others specify that this granularity is Non-Firm only. Upon comparison of a few major potential participants published OATTs, there were some other differences of note[1]:

 

TSP

Lowest Granularity Rate

Observation

BPA

$4.70/MWh Hourly Firm and Non Firm

Singular rate is abnormal

PAC

$8.93/MWh Peak, $4.25 Off-Peak Hourly Firm and Non-Firm

Differs by Peak and Off Peak

Idaho

$6.42/MWh Peak, $3.59/MWh Off-Peak Non-Firm Hourly

No Hourly Firm

NV Energy

$10/MWh Peak, $0 Off-Peak Non-Firm Hourly

Off-Peak rate is $0

APS

$11.31/MWh Peak, $6.32/MWh Off-Peak Hourly Firm Summer Rate

$6.76/MWh Peak, $3.78/MWh Off-Peak Hourly Firm Non-Summer

Differs by Season and Peak and Off-Peak

 

Given that some potential participants did not have an hourly firm rate, and others there was not a differentiation between firm and non-firm at this granularity, PGP recommends that hourly Non-Firm could be a reasonable backstop rate for those that do not procure longer term transmission. Depending on the resource type and ability to optimize between rates, this may also continue to encourage bilateral procurement of transmission. The benefits of congestion rents that come with long-term transmission should serve as an additional incentive to purchase longer-term transmission (where available). Given this is not an RTO, this is an important mechanism to recognize the continued need to fund the transmission system locally through the TSPs and limit free ridership.

Other considerations that should be more clearly addressed in the proposal include settlement considerations raised on the stakeholder call such as how this revenue gets allocated back to the TSP, and if/how this cost can be appropriately incorporated in bidding behavior, which again should be easier with an hourly backstop rate. Given some stakeholder-listed objectives of the settlements such as simplicity and transparency, PGP proposes that further refinement of this piece of the proposal is necessary to fully align it with the underlying intent of the proposed requirement. Whatever the final solution is, this issue will need careful monitoring over time to evaluate if the policy is working as intended and/or having any unintended consequence.


[1] https://www.bpa.gov/-/media/Aep/rates-tariff/current-transmission-rates/2022-transmission-rate-schedules-and-grspsfinal.pdf, http://www.oasis.oati.com/woa/docs/PPW/PPWdocs/Rate_Table_20220601-more_decimals.pdf,

http://www.oasis.oati.com/woa/docs/IPCO/IPCOdocs/IPCO_Current_Transmission_Rates_08-26-22.pdf, http://www.oasis.oati.com/woa/docs/AZPS/AZPSdocs/2022_Effective_Formula_Rates_20220601.pdf

 

3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

No further comments at this time. 

4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Compared to the prior version, PGP supports the changes in the current draft to improve the market timelines and improve the ability to honor OATT right priorities in the market.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

PGP supports the additional mechanism for recovery of lost short-term resale revenues upon the expiration of legacy contracts. As this is meant to address the loss of a portion of the revenues associated with a legacy contract, this is a separate issue than the new entrant or resource participation framework requiring transmission or defaulting to a pre-determined rate discussed in question 2 above. Given these are separate issues, this adjustment to the recoverable transmission revenues should be included in the final proposal using the same methodology applied to the new transmission builds as suggested in section II.B.1 (b).

PGP also continues to support the adjustments required for the net wheels through on the system but given the differences in hourly rate structures of potential participants explored in question 2 above, additional nuance on the granularity of this calculation may be required to accurately account for this component of lost revenues. One suggestion would be to clarify that this is an hourly calculation.

Excluded in this Draft Final Proposal is recovery of affiliate sales in this calculation. Exclusion of affiliate sales again assumes an alignment between BAAs and TSPs that is not consistent accross all potential EDAM entites, and exlcusion of affiliate sales could lead to cost shifts between transmission customers and LSEs. PGP encourages further dialogue with the affected entities, namely BPA, to improve mutual understanding of this issue.

Regarding the true-up mechanism, the carry-forward approach as opposed to the year-end true up may introduce cost shifts or implementation challenges if additional detail is not included to address the staged implementation timelines that are likely to occur with potential participants. If this true up is allocated in the BAAs that were in the market during the shortfall or surplus time period, this should be able to be incorporated in the methodology. In either approach, additional consideration of how to accurately deal with mid-year entry may also be required.

 

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

PGP appreciates that the EDAM proposal seeks to address stakeholder concerns regarding the preservation of appropriate rights of legacy transmission holders, including the ability to schedule on transmission beyond the day-ahead time frame. The meeting discussion on the bucket 2 pathway 3 redispatch solutions and congestion impacts seemed to offer a proposal to address this concern that may align somewhat with the legacy contract structure with the CAISO. At the November 14th meeting, and in the recent presentation on the topic at the RIF, stakeholders expressed that the congestion costs from redispatch on these contracts tended to net out over time. Recognizing that different footprints and a changing resource mix are at play, it would still be beneficial for CAISO to share an analysis of the net redispatch cost to the CAISO over time compared to the total trades under the legacy structures within California, including sharing of other statistics such as largest single event, any seasonal trends, or any other analysis that may help non-CAISO entities to better understand the potential impact of this aspect of the proposed market design. PGP also notes that this is another area where there may be some risk of cross subsidization between BAAs if the TSP footprint and the BA footprint do not align.

 

7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

PGP supports the changes in the RSE to better align timelines with the market run and the ability to get advisory results up until the binding run, and improved documentation of the proposed use of WSPP Schedule C contracts within the Resource Sufficiency Evaluation, and the alignment of resource forecasts with the RSE. The VERS framework in particular seems to better align the imbalance reserve product introduced in the DAME initiative, the diversity benefit calculations, and the WRAP interoperability.

There are still areas of the proposal that require further detail. The language about load bidding rules to facilitate market clearing of DR resources that are used as load modifiers for the RSE needs to be further refined, as it is unclear how this interacts with convergence bidding in certain BA footprints.  The description of including the load modifications for CAISO RDRR resources in the DA forecast but then only using them if “the requisite conditions materialize in the RT market” undermines the strength of the DA RSE and appears liketly to effectuate the backfill described in the prior paragraph in RT unless there is some mechanism to carry this forecast adjustment forward into RT. If these resources are to be used purely in the case of emergency, further discussion as to whether this constitutes an EDAM RSE failure needs to occur. In this situation, it may be appropriate to have an EDAM RSE failure, while a RT/EIM failure and consequences could be avoided through the use of these resources or through lack of the shortfall materializing. Given the significant role of demand-side resources in the recent reliability events of the summer of 2022, at minimum, if these programs are to be included in the forecast as an adjustment to the EDAM procurement by the CAISO and facilitate passing of the RSE, further analysis of potential pricing issues that this may introduce, consideration of if this indicates a DR-specific uncertainty adjustment in EDAM, or further refinement of the existing rules regarding the ISO’s RDRR resources and their participation framework may be required. If this is to be refined in a separate stakeholder initiative, that should be explicitly clarified in the proposal so that participants can engage on that issue if needed. As designed this appears likely to effectuate the equivalent of RT load conformance when the load gets added back to the forecast, which is not appropriate or aligned with stakeholder goals expressed in EDAM, the Price Formation Enhancement Initiative, Day Ahead Market Enhancements, and/or WEIM Resource Sufficiency Evaluation initiatives.

To facilitate short-term resource sufficiency, PGP supports the concept of an on-demand RSE calculation combined with an RSE obligation trading platform but continues to question if CAISO is the appropriate host for such a function, given this may be a valuable tool for managing seams and inter-operability between the EDAM footprint and entities that are in the WRAP with EDAM participants. Consideration of expansion of such tool to include non-EDAM participants may be required for it to function as intended and provide the full value that this concept offers. PGP recommends that at minimum, CAISO coordinate development of this tool with the Western Power Pool to ensure the functionality aligns with the WRAP operations program.

PGP also requests further clarification of “Additional Balancing Capability” and its consideration in the RSE calculations. Now that this has been explicitly addressed in the WEIM RSE calculations, it may make sense to likewise include in the DA RSE.

 

8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

PGP’s perspective is that the current proposal meets the objective of not encouraging RSE failures or leaning on purpose, but that any penalty less than Cost Of New Entry (CONE) has the potential to lower incentives to procure long-term capacity, increasing risks across the footprint as a result. While recognizing that RA requirements are considered “out of scope” for the CAISO and the EDAM market design, they introduce inequities and inconsistencies for market participants that are very challenging to overcome without a common RA requirement.

Macro issues aside, PGP supports the direction of the proposal noting that the introduction of the de-minimus threshold and the volumetrically-based penalty structure are appropriate, as is the use of on-peak penalties only. Additional information regarding how the 50% threshold aligns with the overall probability of exceedance would add to the interpretation of the tiers. PGP would also like to see further documentation on the 1% escalation factor and how it would apply when there are Tier 2 and Tier 3 failures in the same rolling window, and consideration of a longer time threshold that aligns more directly with RA seasons for the definition of “repeated failures”. A rolling 30 day metric does not seem aggressive enough, given these issues are likely to be seasonal. Continued monitoring and reporting on the RSE failures should support ongoing enhancements of these mechanisms.

An additional concern is that the penalty does not seem to apply in hours where the hourly BAA price was higher than the bilateral On-Peak block price. Noting that a.) there are outstanding concerns around liquidity that likely need some thresholds defined, (ex. Trades and/or volumes) and may require a fall back to market prices and b.) there are situations where the hourly LMP price might be slightly higher than the bilateral price in all hours but would result in a radically lower penalty than minor failures when the bilateral price is slightly higher, there should likely be additional backstop provisions such as a minimum penalty for RSE failures outside the de-minimus band, and liquidity definitions added to the proposal. Participants should not be able to gamble on the hourly price being higher to avoid curing of deficiencies. One suggestion would be to include the average BAA hourly price in the maximum function such that the minimum penalty for tier 1 would be a 25% adder to the BAA price at the volume of the maximum failure. This would keep the structure the same but contemplate the conditions mentioned above.

Further examples including exploration of lower-price scenarios or scenarios where all hourly prices clear above the DA bilateral price would aid in the potential participant’s understanding of the proposed structure, as would examples focused on failures in oversupply conditions.

9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

PGP supports the concept of a configurable diversity benefit with a conservative allocation upon market go-live, but recommends this portion of the proposal or the starting place and phasing approach be further defined in the final proposal. Further detail on how it would be appropriately allocated in this conservative operation mode is required, and/or an analysis of if the net EDAM transfer constraint is a sufficient metric to enable full use of the diversity benefit. Per the recently released analysis by Energy Strategies[1], this represents a significant portion of the potential EDAM benefits, so it should be utilized as fully as possible as early as practicable.

Both EDAM and DAME need additional clarification about how the diversity and imbalance reserve procurement calculations align with forecasting requirements, whether the BAAs are using their own forecasts, or the CAISO has their own, and what this indicates for historical datasets required to seed the analysis. It may make sense to have this as a BA-specific election, meaning they could choose to limit their own participation in the pooling if desired, but would then need to bring more resources to the market. Further analysis of if this approach would be appropriate or implementable is recommended.

 


[1] http://www.caiso.com/Documents/Presentation-CAISO-Extended-Day-Ahead-Market-Benefits-Study.pdf

 

10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

While this concept may alleviate some concerns of inconsistent treatment for the CAISO due to the interaction with RA programs, and it may serve as a risk-management tool for other EDAM participants, recommends further analysis of the potential impacts on the calculation and allocation of the diversity benefits and RS requirements prior to inclusion in the final proposal. Further analysis may also consider how this impacts any historical reliability analysis that was used to structure the RA programs in CA or the WRAP, and if a change such as this has impacts on the program at large that need to be considered.

11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

 Given the direct intersection with the WEIM RSE evaluation, and the diversity benefit and imbalance reserve covered under the DAME initiative, PGP again requests further documentation of the intersect of these market processes and policy initiatives in the Final Proposal, including clarification on areas that are concluded and areas that are still evolving.

12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

Given the differences in virtual market participation and potential impacts to RC volumes and RUC commitments, PGP requests further analysis of if RUC cost allocation should be focused in on the drivers at the BA-level, rather than allocated across the market, given the various convergence bidding structures will likely drive different RC and RUC requirements. Please note if this is to be further refined in the DAME initiative or if this is covered by EDAM.

13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

No comments.

14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

PGP recognizes that convergence bidding is generally offered as part of all FERC jurisdictional markets but that this is a new and unique market design construct, and may warrant unique rules and participation models. PGP appreciates that there is a transition option included in the proposal and would like to see this maintained in the final proposal. PGP recommends that while it will be important for the Market Surveillance Committee to analyze and monitor if there are any potential issues that may arise through a patchwork virtual participation frameworks, it will be equally important for the market monitor to again analyze and justify the benefits and challenges of any virtual participation that exists today, and further evaluate its impacts on the EDAM market as it goes live.  Of note, different virtual participation could lead to impacts on the RC requirements for each market participant, and this difference will need to be explicitly evaluated and incorporated into market processes to avoid inequities and/or cost shifts from different RUC requirements driven by convergence bidding impacts on the market.

 

15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

The proposal explains that for non-CAISO participants, off system resources are allowed to economically bid because they have transmission, but have to be in a WEIM BAA. These external resources can be economically bid only at the intertie of the EDAM BAA where the load served by the designated resource is located. PGP would like further documentation as to why CAISO intertie bidding with non-EDAM BAAs is different than other market borders. This inconsistency is well documented but not well justified in the proposal as drafted. CAISO should elaborate as to why the reliability of supply concerns for intertie bidding at other EDAM BAAs are not applicable for CAISO intertie bidding at non-EDAM borders. The final proposal should at minimum expand the language to clarify that system sales or grouped resources that are modeled in WEIM may also participate as external resources in EDAM. Participation of these resources will smooth the transition when some WEIM entities have fully joined the EDAM and others have not.

16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

PGP appreciates the ongoing dialogue on this issue and the removal of certain elements of the discussion of the zonal approach from the straw proposal as well as removing some of the problematic language around renewable energy certificate (REC) contracts.  The majority of the comments contained in PGP’s prior comments regarding the long-term durability of the proposal were not substantively addressed and will not be repeated here; however, PGP continues to stand by those comments and looks forward to future dialogue on this topic.  

 

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

PGP’s market principles include fair cost and revenue recovery in the marketplace, not simply “lowest cost” as the objective of the market. The lowest system cost with inaccurate attribution does not align with a market objective of fair compensation for services and attributes brought to the market, such as GHG attributes.  This appears to place a preference for low prices over a preference for fully recognizing the emissions reduction objectives of state pricing programs, but without a full articulation of how and why this preference is an appropriate way to strike a balance between these potentially competing interests.  PGP recognizes the issue with “destroying the convexity of the problem” when introducing the dynamic GHG constraint. The examples provided in the meeting on November 14th were helpful for understanding the challenges in introducing this. The tradeoff of requiring the occasional out of market payment on the incremental approach is likely less than the issue of poor resource attribution and under valuation of the GHG component that is inherent to the EIM design.  Broader analysis of the likely frequency of the requirement of out of market payments in the dynamic calculation would improve the ability of stakeholders to understand the tradeoffs. PGP would also like to see further analysis exploring the exception for RSE and if it would be more accurate or appropriate to default to an unspecified source rate for imports in the event of RSE failure or any situation that results in a lack of sufficient resource for attribution.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

No further comments at this time

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

Over the course of discussions on GHG accounting throughout the EDAM stakeholder process, the CAISO has indicated a willingness for further consideration of GHG proposals, including the zonal approach and the approach proposed by LADWP.  In the proposal, the CAISO notes that, if necessary, the CAISO will work with stakeholders and regulatory agencies to consider design improvements based on actual market experience and regulatory changes, including considering different design approaches identified and considered in the EDAM stakeholder process.  One of the key concerns raised by PGP with respect to the current proposal is its impact on emissions and whether and how the proposal effectively implements state policy objectives to reduce GHG emissions. PGP requests that the CAISO consider how it will evaluate the emissions impact of its proposed design and whether and how additional data can be made available to market participants to better enable this assessment.

PGP also continues to have concern with proposal to modify the geographic boundary of reporting to the geographic boundary of the state (as opposed to the BAA boundary) absent further clarification or direction to do so in state regulations.  It appears that CAISO’s proposal is to make this change in the WEIM in parallel with the implementation of EDAM. As noted in prior comments, the Washington Department of Ecology regulations differentiate reporting obligations between electricity importers who are identifiable on an e-tag and those that are multi-jurisdictional retail providers.  The regulation does not address the difference between how these two differently situated entities report in the context of the WEIM or EDAM.  The regulation also does not directly address treatment of the Bonneville Power Administration, which is a multi-state BAA and has unique statutory obligations associated with its energy sales.  PGP is specifically concerned regarding issues related to how Bonneville will be treated and how that might impact reporting obligations in Washington.  CAISO should not implement this proposal absent further discussion and rulemaking activity at the state level.

PGP further requests clarity with respect to how CAISO will implement its proposed changes in the context of the WEIM, and whether and how CAISO will address a situation where state level rulemaking is not complete on a timeframe consistent with the proposed implementation of the modified design.

 

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

 PGP  has concerns about transfer revenue calculations, particularly as they relate to multi-segment transmission into and out of the CAISO. PGP would like to see further examples of how multi-segment paths with alignment of rights-holders may or may not receive transfer revenues. PGP recommends that where feasible, multi-segment paths with the same rights be treated as a single leg for transfer revenue purposes. Given the modeling of intertie bidding, it appears that these ties are already modeled as multiple paths, so further understanding of other approaches that recognize the realities of the system seems feasible.

Regarding the new transmission requirement for participating resources,more clarity is needed on if the resulting de facto short-term purchases receive congestion rents during the times of use of the system, or if only long-term rights holders would have access to congestion rents. The latter approach seems more aligned with the intent of the additional provisions.

Regarding the congestion allocation within the BAs, CAISO continues to propose that all transfer and congestion rents except for Bucket 2 Pathway 2 go through the EDAM Entity, yet has provided no assurance that they will provide sufficient information to the EDAM Entities to actually perform the suballocation of internal congestion rent and transfer revenues to Transmission rights holders. If this is an issue that is unique to BPA, perhaps a BPA-specific discussion of this topic would be warranted, or some additional time on this topic in a future settlements workshop.

21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

Given the large footprints and comparatively simple structure of many utilities who may be interested in joining the EDAM, a separate conversation with entities who are nested in BPA’s BAA who have transmission service and/or resources who will participate in the EDAM market may be required to address potential multi-layered settlement issues. Nested LSEs and/or BAs will require further attention from an implementation standpoint to avoid inappropriate cost shifts and enable maximum market participation. Settlement examples that further address misalignments between BAA and TSP footprints would improve the regional understanding of the proposal.

22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

PGP agrees with the ratemaking objectives expressed by the CAISO. The estimates provided regarding potential average implementation costs of $1.2 Million per entity is a valuable piece of information. To interpret this estimate, PGP recommends the CAISO share a review of the estimates vs the actual implementation costs of EIM entities, and a differentiation in the fees estimate between those who are already WEIM participants and those who are not. Aligning with the methodology shared in the proposal, PGP would also like to see an estimate of the $/MWh EDAM administration charge assuming WEIM-level participation in the market.

23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

PGP appreciates the progress to date and all of the effort from CAISO staff to be responsive to questions and concerns. We look forward to continued conversations on the areas that still lack stakeholder alignment and will continue to engage on the initiatives that directly intersect with the EDAM framework, recognizing that many aspects of the comprehensive market design are not included in this document. PGP requests that time in the final presentation be dedicated to directly addressing the areas of highest importance that will continue to evolve in other stakeholder processes.

 

Public Interest Organizations
Submitted 11/22/2022, 11:58 am

Submitted on behalf of
Sustainable FERC Project and Western Resource Advocates

Contact

Kelsie Gomanie (kgomanie@nrdc.org)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

Western Resource Advocates and Sustainable FERC Project (Public Interest Organizations “PIOs”) appreciate the opportunity to respond to the Extended Day-Ahead Market Revised Final Proposal issued by the California Independent System Operator (CAISO) on October 31, 2022.  WRA and Sustainable FERC are public interest organizations that advance policies to further a low-carbon grid and reduce harmful emissions from fossil-fuel generation through market-based solutions. We support the development of a successful, well-designed Enhanced Day-Ahead Market (EDAM) to efficiently and reliably commit units in the day-ahead timeframe, thereby cutting emissions and lowering costs. Addressing the climate crisis will require greatly enhanced Balancing Authority (BA) coordination, and a successful EDAM is a significant step with the ultimate goal a fully integrated, transparent, and accessible Regional Transmission Organization (RTO) with meaningfully representative governance.

PIOs appreciate all of CAISO’s efforts to extend its Day-Ahead Market to others in the West as quickly as is possible. Studies have repeatedly demonstrated that enhanced BA coordination cuts costs, improves reliability, and reduces emissions. Conversely, maintaining the status quo results in relative inefficiency and waste and unnecessary accumulating emissions. Given the need to address the ever-growing climate crisis, we urge haste while supporting deliberate and well-considered market design.

Because we seek a successful, broadly-supported, inclusive, and transparent EDAM, we support design elements that: (1) maximize market optimization; (2) encourage maximum participation by existing and new EIM entities; (3) encourage the maximum participation of transmission and generation; (4) garner the support of transmission customers and independent power producers; (5) promote transparency and accessibility; (6) promote the full participation of all resources, including demand response and storage; and (7) safeguard reliability. Finally, with regard to greenhouse gas (“GHG”) compliance, we support options that reduce compliance leakage by limiting or eliminating secondary dispatch and provide transparent reporting of post-dispatch GHG emissions.

We have provided comments on the sections regarding the EDAM Participation Model, Transmission Availability, and Greenhouse Gas (GHG) Accounting and have left the other sections blank – a blank section does not indicate full support for the content of the section. In summary, PIOs are supportive of elements of the EDAM Participation Model and Transmission Availability that promote maximum transmission availability with equitable access and transparency. PIOs are also generally supportive of the GHG Accounting approach outlined in the Draft Final Proposal and request clarification, as well as continued evaluation, of certain elements when the EDAM is implemented.

2. EDAM PARTICIPATION MODEL: Please provide your organization’s comments on the proposed structure of the EDAM participation model, including load and resource participation, as described in section II.A.1 of the draft final proposal:

In the Draft Final Proposal, CAISO added a new proposed requirement for generators in an EDAM BAA to have one of three types of transmission service in place as a condition of participation in the market. PIOs appreciate how CAISO has proactively worked with key stakeholders to find modifications to the specific proposal included in the Draft Final Proposal that may address this issue while assuaging concerns that were raised with certain elements of it. PIOs shared some of the concerns that were raised with the specifics of how this requirement was written in the EDAM Draft Final Proposal, however, the adjusted design presented during the EDAM Draft Final Proposal Stakeholder Meeting on November 14 was encouraging and signals that significant progress has been made. Allowing resources to bid into the market, subject to a transmission charge based on an hourly or daily point-to-point rate, will mitigate the concerns regarding free-ridership and cost-shifts in paying for the transmission system from this type of use in EDAM, while remaining workable for generators that wish to participate in the market. Although we recognize that additional modifications and details may need to be developed as the EDAM design is finalized, PIOs are appreciative of CAISO Staff’s proactive approach and engagement with stakeholders on this aspect of the proposal.

While PIOs are supportive of the direction CAISO is taking with regards to this aspect of the proposal, we offer the following comments to give more color to our perspective. Conceptually, PIOs recognize that some type of transmission requirement is not unreasonable since, unlike in an RTO paradigm, EDAM will only consist of the day-ahead market product and not all transmission cost shifts that would need to be worked through under an RTO construct will be addressed. Therefore, use of a mechanism to recover costs of transmission service from generation consistent with Open Access Transmission Tariff (OATT) terms is reasonable. To that end, we propose the following considerations as CAISO figures out the details of the exact transmission requirement in concert with stakeholders most impacted by this element of the proposal: To that end, we recommend CAISO staff consider the following as the details of the transmission requirement are finalized:

  1. The ultimate transmission requirement for generators in EDAM BAAs should seek to minimize transmission cost shifts, be mindful of impacts to load participating in EDAM, and avoid imposing costs on generators that discourage participation or substantially reduce market efficiency by acting as a de facto hurdle rate
  2. CAISO should seek to maximize resource participation and transmission commitment to facilitate clean energy development and deployment.
  3. Any transmission costs recovered through this mechanism should warrant further discussion and consideration of whether it should impact (reduce) the TRR recovery bucket.  
3. CONFIDENCE IN MARKET TRANSFERS: Please provide your organization’s comments on the topic of confidence in market transfers design as discussed in section II.A.2 of the draft final proposal:

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4. TRANSMISSION AVAILABILITY: Please provide your organization’s comments on the overall design for how transmission is made available to the market under the transmission “buckets” framework and the different underlying pathways for how transmission customer exercise their transmission rights or otherwise make transmission available to the market as described in section II.B.1 of the draft final proposal:

Transmission availability is foundational to integrating renewable energy in the day-ahead market, efficiently transferring supply across the footprint to cost-effectively serve load, and maintain grid reliability. PIOs appreciate CAISO’s efforts to develop a proposal that seeks to maximize the amount of transmission made available and continues to support the general transmission availability framework. PIOs are encouraged by the modifications made throughout the stakeholder process to take steps toward achieving these goals and gathering broad support for the approach. As we see it, this proposal is an intermediary step towards a full RTO: maximizing transmission made available to the market, maintaining the OATT structure and incentives to retain transmission rights, and addressing the loss of short-term transmission revenue through an uplift.

PIOs support the CAISO’s proposal to change the deadline for release of transmission through Bucket 2 Pathway 2 from 6am to 9am. This change will better align the timing requirements between Bucket 1 and Bucket 2, resulting in more equitable treatment between all entities providing transmission to the market.

PIOs also support the change to the Bucket 2 Pathway 3 proposal that would have EDAM entities utilize congestion revenues to hold transmission rights holders harmless, to the extent possible, when their rights are utilized after the day-ahead market run. We view this modification as an important step in aligning the EDAM with OATT arrangements and in gathering support for the overall transmission framework proposal. This change enables all unscheduled transmission rights to be made available to the market to optimize EDAM transfers while also helping preserve the value of holding transmission rights in EDAM, which is critical to reducing the possibility for long-term devaluation of these rights.

PIOs believe the design put forth in the Draft Final Proposal to hold transmission customers harmless, to the extent possible, is a workable solution to maximize support for the proposal, minimize impacts from potential redispatch costs, and maintain the value of these existing rights. While this proposal seems workable in principle, PIOs encourage CAISO to continue engaging with stakeholders on this topic as we expect additional discussions will be needed to develop the details for proper implementation of this proposal.

5. TRANSMISSION AVAILABILITY: Please provide your organization’s perspective on the historical transmission revenue recovery design proposed through the EDAM as described in section II.B.1 of the draft final proposal:

The Draft Final Proposal maintains much of the previous design for transmission revenue recovery, enabling transmission providers to recover historical transmission revenues to account for potential reduced sales of short-term transmission products. PIOs support this proposal, as it avoids the inefficiencies of including a hurdle rate in the market optimization while still addressing concerns regarding transmission compensation. Additionally, this proposal puts EDAM on a “glide path” towards a more RTO-like framework for transmission compensation, as the volumes of costs recovered through this mechanism will likely decrease over time.  

PIOs also support the proposal to collect TRR shortfall from load only, rather than load and supply. This allocation methodology is more appropriate for EDAM, and we believe it will be more efficient for the overall market design.

We also note that, depending on the ultimate design of a transmission requirement for generation in an EDAM BAA to participate in the market, it may be necessary to revisit the transmission revenue recovery design framework. The design of the two components together should ensure that lost short-term transmission revenues are recovered and that there is no over collection due to the interaction of the two different revenue collection methods. PIOs also recommend the CAISO submit a progress report on the performance of the two revenue collection methods to the Regional Issues Forum (RIF) on this element, once the EDAM is implemented.

6. TRANSMISSION COMMITMENT: Please provide your organization’s comments on any other aspects of the transmission availability design in EDAM:

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7. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the design of the EDAM RSE, including components of the evaluation and the consideration of different resources within the evaluation as described in section II.B.2 of the draft final proposal:
This includes comments on: the ability to conduct advisory sufficiency evaluations prior to the binding run; running the RSE on a BAA stand-alone basis without a discrete deliverability test; the RSE requirements, and counting rules for difference supply types; and load participation rules each EDAM BAA will be responsible for enforcing relating to demand response use and VER forecast counting.

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8. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on the proposed design establishing the consequences for failing the EDAM RSE as described in section II.B.2 of the draft final proposal:
This includes both the different surcharge for levels of failure as well as the structure of the surcharge itself.

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9. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the ISO proposed design for pooling EDAM entities passing EDAM RSE for evaluation jointly, as a pool, in the WEIM RSE as described in section II.B.2 of the draft final proposal:

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10. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s perspective on the additional tool for managing supply in excess of RSE requirements, the net EDAM export transfer constraint as described in section II.B.2 of the draft final proposal:

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11. DAY-AHEAD RESOURCE SUFFICIENCY EVALUATION (RSE): Please provide your organization’s comments on any other elements of the EDAM RSE not raised by, or discussed in, the questions above:

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12. INTEGRATED FORWARD MARKET (IFM) AND RESIDUAL UNIT COMMITMENT (RUC): Please provide your organization’s comments on the IFM and RUC design as described in sections II.C.2 and II.C.3 of the draft final proposal:

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13. MARKET POWER MITIGATION (MPM): Please provide your organization’s comments on the proposed Market Power Mitigation (MPM) approach as described in section II.C.4 of the draft final proposal:

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14. CONVERGENCE BIDDING: Please provide your organization’s comments on the proposed convergence bidding design and the associated transition period being proposed as described in section II.C.5 of the draft final proposal:

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15. EXTERNAL RESOURCE PARTICIPATION: Please provide your organization’s comments on the proposal for external resource participation in the EDAM, as described in section II.C.6 of the draft final proposal:

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16. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s overall comments, including potential suggested enhancements, on the resource specific approach to GHG accounting as described in section II.C.7 of the draft final proposal:

PIOs recognize that in order for the EDAM to be implemented in a timely manner CAISO must have in place a GHG accounting method that can be implemented.  From this perspective, we generally support the resource specific approach to GHG accounting as a starting approach of the EDAM. We appreciate that the CAISO has attempted to reduce secondary dispatch associated with this design and has implemented market rules to reduce the potential of it occurring. Reducing emissions is the primary objective of our groups in supporting establishment of the EDAM. However, while an improvement, the resource specific approach as currently contemplated does not eliminate the potential of secondary emissions. Therefore, we have two recommendations going forward. First, ahead of issuing a Final Proposal, we request clarity on the feasibility of the approach offered by the Vistra Corporation (Vistra) representative, Cathleen Colbert, during the Market Surveillance Committee (MSC) Meeting General Session on October 21, 2022. Second, careful and continuous monitoring and reporting of the magnitude of secondary dispatch that occurs after EDAM implementation is a key component for our support. Secondary dispatch that continues to occur unchecked may inadvertently disincentivize the retirement of coal plants that fulfill the secondary dispatch and provide long-term artificial life-support to coal plants that may have otherwise retired.

Further, PIOs recommend that changes be made to the market design rules if a sizable amount of secondary dispatch occurs, especially if it is repeatedly being backfilled from the same resource.

PIOs also support the future stakeholder process to explore future design improvements post-implementation. Once EDAM is implemented, it is important to evaluate if the GHG accounting framework effectively works to meet the foundational goal of GHG accounting to incentivize renewable and carbon-free resources and charge optimal costs for fossil fuel exports from GHG regulation areas or fossil fuel imports into GHG regulation areas. To that effect, PIOs recommend CAISO staff monitor and reduce the deviation between actual optimized prices and scheduled prices pre-dispatch to ensure deeming concerns are resolved and begin conversations on the reporting of post-dispatch settled GHG emissions for all stakeholders. As the EDAM continues to operate, additional elements that PIOs recommend CAISO staff evaluate and report on include:

  • What are the impacts to the overall GHG optimization due to transfers between GHG regulation areas and non-GHG regulation areas?
  • Are there concerns of “edge” cases and the issue of implications of dynamic GHG attribution
  • Is price suppression occurring due to how GHG pricing is done? If so, what can be done to rectify that?
  • What are the implications of export constraints and their inclusion or lack thereof?

Also, PIOs propose CAISO staff to provide clear definition of “Pseudo tied resources” and request clarity on not only how these resources will not be attributed if pseudo tied to the BAAs in the GHG regulation area. As in, PIOs request clarity on the mechanics of this determination process and communication of this treatment of RA resources, to state air quality regulators.

17. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the design of the GHG reference pass as the GHG counterfactual:

PIOs are encouraged by the design of the GHG reference pass as the GHG counterfactual and recommend the CAISO staff open a stakeholder initiative as the EDAM is implemented to evaluate other designs as the GHG counterfactual given the potential for additional GHG regulation areas to form within the EDAM footprint.

18. GREENHOUSE GAS ACCOUNTING: Please provide your organization’s feedback on the net export constraint topics including: design, interaction with the GHG counterfactual, exceptions for RA capacity, and analysis:

PIOs understand that CAISO is still considering whether to base the net export constraint on optimal net transfers or net export transfer capability and appreciate the CAISO’s analysis of the GHG net export constraint’s potential limit on transfer to a GHG regulation area, reliability impacts, and pricing impacts. As CAISO makes a decision on what criteria to base the net export constraint on, and as EDAM is implemented, we recommend the CAISO staff take into account the input provided by Vistra during the MSC Meeting General Session and Department of Market Monitoring (DMM).

19. GREENHOUSE GAS ACCOUNTING: Please provide any other feedback on the resource specific approach to GHG design not captured in the questions above:

PIOs appreciate the willingness of the CAISO to provide emissions intensity information for in-state generation and the total MW of BAA-level transfers, as well as the CAISO’s stated intent to begin a longer-term effort to provide states with data on centralized market transactions to help meet other state clean energy programs, with and without carbon pricing programs. PIOs support these actions as being reflective of progress toward the clean energy transition and the CAISO staff willingness to expand the framework. PIOs also recommend the CAISO aligns with the Department of Market Monitoring (DMM) to evaluate certain elements of the GHG accounting approach. PIOs also request CAISO staff to initiate conversations in 2023 with SPP – Markets+ - implementation staff to discuss ways for a “one-stop” reporting of all GHG information arising from the settled day-ahead market transactions. PIOs are willing to be facilitators of such conversations and also engage with WREGIS (WECC based framework for collecting renewable energy credit data) as a venue for all settled day-ahead market based GHG reporting to be housed. Waiting until the EDAM goes live to consider reporting is not an ideal approach to implement a robust, fair and transparent, day-ahead market product for energy.

20. TRANSFER REVENUE AND CONGESTION REVENUE ALLOCATION: Please provide your organization’s comments on the proposed transfer revenue and congestion revenue allocation approach as described in section II.D.1 of the draft final proposal:

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21. SETTLEMENTS: Please provide your organization’s comments on the settlements design described in section II.D.2 of the draft final proposal:

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22. EDAM FEES FRAMEWORK: Please provide your organization’s comments on the EDAM fees framework, particularly the implementation fee and administrative fee framework, as described in section II.E of the draft final proposal:

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23. GENERAL COMMENTS: Please provide your organization’s comments on any other elements or aspects of the EDAM draft final proposal:

PIOs continue to broadly support EDAM, with the hope that the transmission provision proposal will lead market participants on a glide-path to an RTO in the West. We believe a flow-based transmission framework that enables transparent use and allocation, maximizes efficiency, and ensures fairness in compensation will result in significant benefits for participants across the footprint while integrating the maximum amount of clean energy generation.

Public Power Council
Submitted 11/22/2022, 02:20 pm

Contact

Lauren Tenney Denison (tenney@ppcpdx.org)

Michael Linn (mlinn@ppcpdx.org)

1. GENERAL COMMENTS: Please provide a summary of your organization’s comments on the Extended Day-Ahead Market draft final proposal:

PPC Comments on CAISO’s Draft Final Extended Day Ahead Market Proposal

The Public Power Council[1] (PPC) is optimistic and encouraged in the potential to develop a day-ahead market that creates benefits for end use customers across the West.  In order for any day-ahead market to achieve this goal, it must be well designed and broadly supported by a diverse set of Western stakeholders.  PPC members are seeking a market which will allow them to enhance the service they provide their customers through increased economic benefits (both through allowing utilities access to lower cost power supply and by providing an opportunity to capture additional value of existing assets), additional integration of carbon free resources, and more efficient use of the region’s transmission grid.  In seeking these opportunities, PPC members also acknowledge that there are certain parameters which must be met by any organized market.  It will be critical that any potential integrated market maintains reliability, facilitates BPA continuing to meet its statutory obligations, and is administered by a governance structure designed to treat all participants equitably.

PPC appreciates the efforts of CAISO staff to work diligently on this proposal for the past year and to answer stakeholder questions.  We want to acknowledge the workload that staff has taken on in developing this proposal - including hosting working group meetings, regular stakeholder workshops, and being willing to follow up with stakeholders to discuss aspects of this proposal.  Within the timeframe set out for this initiative, CAISO staff has made significant progress on vetting these issues.

At the same time, the process is moving quickly and there are areas where additional detail would be helpful in evaluating the proposal.  This includes better understanding areas where the CAISO has declined to adopt stakeholder recommendations.  Some of these instances are well documented in the proposal, while others are not specifically addressed.  We also appreciate that CAISO staff has in some instances worked quickly to adopt changes which address concerns raised by stakeholders, but this has created a constantly evolving proposal – which can make it difficult to comment adequately on the proposal in its current state.  In other words, PPC finds it challenging to comment on the EDAM structure in as much detail as we would like given that this is the draft final proposal, because elements of the proposal continue to evolve.  We expect that some of the most recent developments are positive changes, but we have not had sufficient time to fully vet some of these proposals given their highly complicated and technical nature. PPC is still considering some of these changes and their impact on our overall evaluation of the EDAM design.

With this in mind, we appreciate that the discussion with the EIM Governing Body and CAISO Board of Governors in December has been changed to a briefing, with a final decision to come in February.  This should give stakeholders additional time to evaluate recent changes and for other