Comments on June 14, 2023 stakeholder workshop

1. Please provide a summary of your organization’s comments on the June 14, 2023 Extended Day-Ahead Market (EDAM) ISO Balancing Authority Area (BAA) Participation Rules stakeholder workshop discussion:

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the Extended Day-Ahead Market ISO BAA Participation Rules Workshop and thanks the Workshop presenters for their proposals. CalCCA provides the following recommendations on the net EDAM export transfer constraint and resource sufficiency evaluation (RSE) failure surcharge and revenue cost allocation:

• The net-export transfer constraint should be turned on at all times;
• The California Independent System Operator Corporation (ISO) should set the confidence factor for the net-export transfer constraint at zero during stressed system conditions;
• During non-stressed system conditions, the ISO should set the confidence factor using historical data specific to non-stressed conditions; and
• The ISO should use a metered demand cost allocation as proposed by the ISO for RSE failure surcharge and revenue cost allocation in the interim.

2. Provide your organization’s comments on the initiative tracks and schedule, including interaction with other initiatives, as described in slides 7-8 of the ISO’s presentation:

CalCCA supports the tracks and schedule for this initiative.

3. Provide your organization’s comments on the net EDAM export transfer constraint, taking into account the presentations by California Public Utilities Commission Public Advocates Office, San Diego Gas & Electric, Southern California Edison, and ISO staff:

The net-export transfer constraint should be in effect at all times, with the confidence factor and reliability margin set based on whether hours are considered stressed or non-stressed.

During stressed hours, the confidence factor should be set to zero to avoid firming up EDAM export transfers based upon non-firm and non-RSE-eligible economic imports when the ISO BAA is facing potential reliability issues. During non-stressed hours, the ISO should use historical data specific to non-stressed conditions to set the confidence factor as long as stressed hours are defined in a way that fully covers the range of conditions that can potentially cause reliability issues.

To define stressed hours, the ISO should adopt its proposed conditions[1] with the additions proposed by Southern California Edison Company (SCE),[2] such that the confidence factor would be set to zero if any one of the following conditions occur as of the 8 a.m. day-ahead ISO BAA operations meeting:

• Operational RA capacity + RA credits < demand forecast + contingency reserve requirement + regulation reserve
  • The stakeholder process should consider defining hours as stressed if forecast excess RA falls below some threshold (e.g., 1,000 megawatts (MW))
• Operational net RA capacity + RA credits < net demand forecast + contingency reserve requirement + regulation reserve
  • The stakeholder process should consider defining hours as stressed if forecast excess net RA falls below some threshold (e.g., 1,000 MW)
• Advisory RSE upward failure quantity – expected day-ahead offers not yet submitted by available RA resources with day-ahead must offer obligations > 0
• Restricted Maintenance Operations
• Transmission Emergency
• D+2 RUC infeasibility
• EEA Watch, Warning or Emergency
• Flex Alert
• If the ISO opts into assistance energy, or if 8-day look-ahead period shows a shortage

Defining stressed hours in this way should fully cover the range of conditions that can potentially cause reliability issues.

CalCCA agrees with the proposed reliability margin setting outlined by the ISO,[3] in which the ISO will calculate the default reliability margin value for each hour by taking the max of (1) replacement reserves based on forecasted most severe single contingency; (2) protection for a non-credible contingency based on weather conditions (fires); (3) gas OFO/curtailments; and (4) (during stressed hours) the Imbalance Reserve Up requirement. The ISO should clarify how it will set the reliability margin value when gas OFO/curtailments are in place, as it is not clear how that condition translates to a MW value.  

[1]             ISO Presentation at 15: http://www.caiso.com/InitiativeDocuments/Presentation-ExtendedDay-AheadMarketISOBAAParticipationRules-Jun14-2023.pdf.

[2]             SCE Presentation at 3: http://www.caiso.com/InitiativeDocuments/SCEPresentation-NetEDAMExportTransferConstraint-EDAMISOBAAParticipationRules-Jun14-2023.pdf.

[3]             CAISO Presentation at 17: http://www.caiso.com/InitiativeDocuments/Presentation-ExtendedDay-AheadMarketISOBAAParticipationRules-Jun14-2023.pdf.

4. Provide your organization’s comments on solutions for allocating RSE failure surcharges and revenues, taking into account the presentations by Southern California Edison, San Diego Gas & Electric and Six Cities:

Please include your organization’s specific recommendation for an interim solution.

For the interim solution, CalCCA supports using a metered demand cost allocation, as proposed by the ISO. While CalCCA supports the allocation of costs on a cost-causation basis consistent with the principles put forth by the ISO,[1] none of the other proposed interim options meet these principles and they will not result in an accurate allocation of costs to market participants that caused the RSE failure. The ISO should implement a metered demand cost allocation for day one of EDAM and consider in track two if and how to modify the approach for the long term.

The ISO should avoid allocating RSE failure surcharges based on showings of Resource Adequacy (RA) resources alone. Many factors drive RSE failures or surpluses in addition to RA showings (including contracts for non-RA supply, RA and non-RA generators on outage, the availability of substitute capacity not shown). For example, if a load-serving entity (LSE) had a 10 MW RA deficiency and 10 MW energy-only capacity in their portfolio, that LSE would not be deficient from an RSE perspective but would be allocated costs as if they were deficient under an approach that allocates costs based on RA showings.

Approaches that target just one of the many causes of RSE failure could worsen cost causation relative to a metered demand approach. Therefore, conducting cost allocation based upon only one of the possible drivers of an RSE failure just because that driver is easier to identify than the others is not just and reasonable. The cost allocation methodology needs to either look at all the major causes costs are incurred or none of them.

While SCE indicates a metered demand allocation “lack[s] emphasis of the importance of forward procurement…,”[1] allocating RSE charges based upon metered demand would not cause “bad acting LSEs” to not meet their RA obligations or, alternatively, incentivize LSEs to meet their RA obligations any more than existing incentives already do. The penalties for RA deficiencies at the California Public Utilities Commission (CPUC) start at $8.88 in the summer months and go up to three times that amount for repeat deficiencies. LSEs also face reputational risk with being on the RA penalty list. If the CPUC’s May 25, 2023, RA Proposed Decision[2] goes into effect, some LSEs face limits on expansions if they do not meet their RA requirements. There is no lack of emphasis on forward procurement. If LSEs do not meet their RA obligations, it is likely a factor of RA market shortages, and not because of insufficient incentives to comply.

[1]             SCE Presentation at 3: http://www.caiso.com/InitiativeDocuments/SCEPresentation-AllocatingRSEFailureSurcharges-Revenues-EDAMISOBAAParticipationRules-Jun14-2023.pdf.

[2]             Decision Adopting Local Capacity Obligations For 2024 - 2026, Flexible Capacity Obligations For 2024, and Program Refinements, R.21-10-002 (May 25, 2023), at 31-41: http://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=509800450.

[1]             Id. at 21.

5. Provide any additional comments on the June 14, 2023 stakeholder workshop discussion:

CalCCA has no additional comments at this time.

1. Please provide a summary of your organization’s comments on the June 14, 2023 Extended Day-Ahead Market (EDAM) ISO Balancing Authority Area (BAA) Participation Rules stakeholder workshop discussion:

The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) is the state-appointed independent ratepayer advocate at the California Public Utilities Commission (CPUC).  Our goal is to ensure that all Californians have affordable, safe, and reliable utility services while advancing the state’s environmental goals.  Our advocacy efforts to protect California customers include energy, water, and communications regulation.[1]

Cal Advocates comments on a number of issues from the June 14, 2023 workshop can be summarized as follows:

• Cal Advocates withdraws its proposal to set the Net Export Transfer Constraint (NETC) Confidence Factor (CF) because the Extended Day-Ahead Market (EDAM) Final Proposal and Draft Tariff preclude other EDAM entities from providing reciprocal treatment. 
• The CAISO, in its role as the Balancing Authority Area market participant (CISO BAA) should adopt Southern California Edison Company’s (SCE) proposal to calculate separate confidence factors for stressed and non-stressed days.
• The CISO BAA should defer to the majority of internal stakeholders’ preferences when setting the NETC CF.  The temporal granularity of the CF should be specified.
• The CISO BAA should adopt an interim solution for allocating Resource Sufficiency Evaluation (RSE) failure surcharges and revenues that takes an initial step towards cost causation rather than settling for pro-rata allocations by metered load share.
• Cal Advocates supports either SCE’s or San Diego Gas and Electric Company’s (SDG&E) two-tiered proposals to allocate RSE failure surcharges and revenues.
• Cal Advocates supports the objectives outlined by the Six Cities to develop a longer-term solution to RSE allocations that prioritizes fidelity to cost causation.
• CPUC-jurisdictional load-serving entities (LSEs) are contributing proportionally more to reliability by using Planning Reserve Margins (PRM) that are higher than the CAISO’s default 15% PRM, and allocating RSE failure surcharges in proportion to their pro-rata share of metered load is discriminatory.

[1] Public Utilities Code Section 309.5.

2. Provide your organization’s comments on the initiative tracks and schedule, including interaction with other initiatives, as described in slides 7-8 of the ISO’s presentation:

Cal Advocates has no comment on this topic at this time.

3. Provide your organization’s comments on the net EDAM export transfer constraint, taking into account the presentations by California Public Utilities Commission Public Advocates Office, San Diego Gas & Electric, Southern California Edison, and ISO staff:

Cal Advocates withdraws its proposal to set the CF as presented at the June 14, 2023 workshop.  The Cal Advocates proposal was based on the assumption that other EDAM entities would provide reciprocal treatment in setting their own CFs.[1]  However, the EDAM Final Proposal clearly precludes this possibility.  The Final Proposal specifies (and the Draft Tariff confirms[2]):

Non-source specific supply that is not under contract cannot participate at EDAM external interties i.e., these supply sources cannot offer supply at EDAM entity external interties, either by self-scheduling or economic bidding. This exclusion is limited to non-specific supply resources at EDAM external interties with EDAM entity BAAs, i.e., not the ISO external interties, and is premised upon the reliability implications noted by the WEIM entities.[3]

In other words, the CISO BAA is the only EDAM entity that will allow non-source specific supply resources to bid at its external interties.  The Final Proposal rules out the same option for other potential EDAM entities, such as PacifiCorp.  Therefore, the CISO BAA would be the only EDAM entity under the final proposal to set a CF.  This represents a structural asymmetry between the CISO BAA and potential EDAM entities, and it is unclear how other EDAM entities could demonstrate reciprocal treatment of non-source specific supply bids at their external interties.  Instead, the reciprocal treatment assumption is violated if other EDAM entities cannot set a non-zero confidence factor.

Instead, the CISO BAA should defer to the majority of internal stakeholders’ preferences when setting the NETC CF.  Likewise, the CF should not be set in the Tariff, but should be subject to revision by an internal CISO BAA process as stakeholders gain more experience with the EDAM and can evaluate whether higher CFs yield net benefits to ratepayers.  Cal Advocates’ proposal to iteratively set the NETC CF over a period of years should be revisited in later years when the EDAM is well-established if non-CAISO EDAM entities opt to allow non-source specific bids at their external interties.

Cal Advocates supports SCE’s proposal to reduce the CF on stressed system days.[4]  To operationalize this proposal, the CISO BAA needs to define appropriate CFs for non-stressed and stressed system days.  SCE proposes a value of less than 20% for stressed system days, although zero is likely to be more appropriate for stressed system days.  Cal Advocates continue to support the use of a non-zero but conservative CF (e.g., 20%) on non-stressed system days as a good faith first step towards trust-building in a regional context.  Likewise, using a 20% CF would help develop a historical record for later analysis of the CF’s impacts on ratepayers.  Cal Advocates recommends that the CAISO provide empirical analysis in the Track A1 draft final proposal to inform the selection of an appropriate value for non-stressed day CFs.  Ideally, this analysis would use a sample comprising at least 5 years of historical data, presented as a series of twelve monthly line graphs with 24 hours on the x-axis.  The lines on these charts would include: weighted-average performance factor (delivered capacity divided by the amount of capacity that cleared the market for that interval), the minimum intra-hourly performance factor, a measure of intra-hour variance such as standard deviation, and the magnitude (in megawatts) of the maximum undelivered capacity in each hour.

Next, the CAISO should specify the temporal granularity it proposes to use to set the CF.[5]  To some degree, the granularity depends on the statistics of the CAISO’s pending data analysis.  If the historical record shows sudden dips in the performance of non-eligible RSE supply that recover within the next interval, this supports setting a more granular CF like the month-hour construct of the CPUC’s Slice of Day approach.  Conversely, setting the CF using a single monthly value would be appropriate if reductions in observed performance are sticky and tend to last for days or weeks at a time.  Again, however, stakeholders need access to the historical data to make the appropriate judgment.   

[1] Public Advocates Office, Setting the Net Export Transfer Constraint, June 14, 2023 at 6.  Available at: http://www.caiso.com/InitiativeDocuments/CPUC-PAOPresentation-NetEDAMExportTransferConstraint-EDAMISOBAAParticipationRules-Jun14-2023.pdf.pdf.

[2] CAISO, Draft Tariff Section 33 – Extended Day-Ahead Market, June 13, 2023 at 33.30.3.  Available at: https://www.caiso.com/InitiativeDocuments/RevisedDraftTariffLanguage-ExtendedDay-AheadMarket-Section33-ExtendedDayAheadMarket.docx.

[3] CAISO, Extended Day-Ahead Market Final Proposal, December 7, 2022 at 92, emphasis added.  Available at: http://www.caiso.com/InitiativeDocuments/FinalProposal-ExtendedDay-AheadMarket.pdf.

[4] SCE, EDAM Net Export Transfer Constraint, June 14, 2023.  Available at: http://www.caiso.com/InitiativeDocuments/SCEPresentation-NetEDAMExportTransferConstraint-EDAMISOBAAParticipationRules-Jun14-2023.pdf.

[5] The CAISO proposes to use hourly data to inform the CF, but it is unclear if the CF itself will vary per hour, day, month, or some other interval of time.  CAISO, Extended Day-Ahead Market ISO Balancing Authority Area Participation Rules: Issue Paper and Track A1 Straw Proposal, May 5, 2023 at 11-12.  Available at: http://www.caiso.com/InitiativeDocuments/IssuePaper-TrackA1StrawProposal-EDAMISOBAAParticipationRules.pdf.

4. Provide your organization’s comments on solutions for allocating RSE failure surcharges and revenues, taking into account the presentations by Southern California Edison, San Diego Gas & Electric and Six Cities:

Please include your organization’s specific recommendation for an interim solution.

Cal Advocates reiterates that the CISO BAA should adopt an interim solution for allocating RSE failure surcharges and revenues that takes an initial step towards cost causation rather than settling for pro-rata allocations by metered load share.[1]  To that end, Cal Advocates supports either of SCE’s[2] or SDG&E’s[3] two-tiered proposals as an interim solution.  In the longer term, Cal Advocates supports the objectives outlined by the Six Cities to develop an enduring solution that prioritizes fidelity to cost causation.[4]  The Six Cities presenters acknowledged during the June 14 workshop that their solution is likely to be unworkable in time for EDAM go-live, so Cal Advocates urges the CISO BAA to adopt a two-tiered interim solution. 

The CAISO’s most simplified proposal to address RSE failure surcharge and revenue allocations is based on a “pro-rata hourly allocation to [scheduling coordinators] based on metered demand.”[5]  This pro-rata approach is discriminatory because it would proportionally allocate relatively more penalty burden to the LSEs that are simultaneously contributing more to reliability.  In 2025, CPUC-jurisdictional LSEs will be tasked with procuring adequate capacity to meet a minimum 17% PRM for the EDAM go-live year, along with the “effective” PRM (ePRM) procured by the investor-owned utilities.[6]  The ePRM increases the reliability margin above the 17% PRM, and the costs are allocated among all CPUC-jurisdictional LSEs.  By contrast, the CAISO’s default PRM for non-CPUC jurisdictional local regulatory authorities (LRA) is 15%. However, recent evidence indicates that some LRAs have had actual PRMs lower than the default.[7]  For example, during the mid-August 2020 heat waves, the CAISO, CPUC and California Energy Commission found that, “[t]he non-CPUC local regulatory authorities vary slightly in their PRM requirements but collectively yield a 14% PRM.”[8]  The mismatch between the CPUC-jurisdictional PRM and that of all other LSEs within the CAISO represents a substantial positive reliability externality for the latter group, at the cost of CPUC-jurisdictional ratepayers.  All ratepayers will bear RSE failure surcharge costs equally if those costs are allocated by using a pro-rata share of metered load.   Meanwhile, CPUC-jurisdictional ratepayers are contributing to, and paying for, a higher level of reliability. 

The Six Cities and Bay Area Municipal Transmission Group raised concerns during the workshop that using RA deficiencies fails to account for a) all resources eligible for the RSE, and b) RA resources that may be on forced outage.  On the first point, whether a resource is eligible or not for the RSE is irrelevant if an LSE fails to comply with its RA requirements.  The structure of SCE’s and SDG&E’s proposals cap the surcharge allocation to any deficient LSE at the amount of RA the deficient LSE failed to procure.  This approach is entirely reasonable and still exposes a potentially large amount of RSE failure to pro-rata sharing.[9]  On the second point, concerns about RA resources that were part of a month-ahead compliance showing but go on forced outage in the operational time frame are misplaced.  LSEs can deal with this problem either by setting a PRM that includes an appropriate implied forced outage margin or they can use a resource counting method that embeds a resources’ forced outage rate into its Net Qualifying Capacity amount (e.g. Unforced Capacity Counting).  LRAs in CAISO are delegated substantial leeway to choose either approach.  Cal Advocates has standing concerns about the reasonableness of LRAs’ resource counting methodologies and how these methodologies might be gamed to more easily comply with already-insufficient PRM requirements.[10]  However, CPUC-jurisdictional LSEs are contributing more to reliability through much higher PRMs than the CAISO 15% default. 

[1] Cal Advocates, Comments on April 5, 2023 stakeholder workshop, April 19, 2023 at question 4.  Available at: https://stakeholdercenter.caiso.com/Comments/AllComments/b32fe181-4578-416d-9ddf-d52b756fa0d9#org-7420c7d8-cf36-417c-9c98-60aa5550d927.

[2] SCE, EDAM RSE Failure Surcharge and Revenues Allocation, June 14, 2023.  Available at: http://www.caiso.com/InitiativeDocuments/SCEPresentation-AllocatingRSEFailureSurcharges-Revenues-EDAMISOBAAParticipationRules-Jun14-2023.pdf.

[3] SDG&E, RSE Failure Surcharge/Revenue Allocation, June 14, 2023.  Available at: http://www.caiso.com/InitiativeDocuments/SDGEPresentation-AllocatingRSEFailureSurcharges-Revenues-EDAMISOBAAParticipationRules-Jun14-2023.pdf.

[4] Six Cities, Allocation of Surcharges for RSE Failures: Framework for a Long-Term Solution, June 14, 2023.  Available at: http://www.caiso.com/InitiativeDocuments/SixCitiesPresentation-AllocatingRSEFailureSurcharges-Revenues-EDAMISOBAAParticipationRules-Jun14-2023.pdf.

[5] CAISO, Extended Day-Ahead Market ISO Balancing Authority Area Participation Rules, April 5, 2023 at 25. Available at: http://www.caiso.com/InitiativeDocuments/Presentation-ExtendedDay-AheadMarketISOBAAParticipationRules-Apr5-2023.pdf.

[6] Proposed Decision Adopting Local Capacity Obligation for 2024-2026, Flexible Capacity Obligations for 2024, and Program Refinements, May 25, 2023, Ordering Paragraph 7 at 115; issued in Rulemaking 21-10-002.

[7] CAISO Tariff 40.2.2.1.(b), May 28, 2023.  Available at: http://www.caiso.com/Documents/Section40-RADemonstration-for-SchedulingCoordinatorsintheCAISOBalancingAuthorityArea-asof-May28-2023.pdf.

[8] CAISO, CPUC, and California Energy Commission, Final Root Cause Analysis: Mid-August 2020 Extreme Heat Wave, January 13, 2021 at 41 and 82.  Available at: http://www.caiso.com/Documents/Final-Root-Cause-Analysis-Mid-August-2020-Extreme-Heat-Wave.pdf.

[9] Cal Advocates supports Six Cities’ long-term framework because the second tier of the interim proposals still exposes ratepayers to potential indifference violations.  However, in Cal Advocates view a solution that is driven by some cost causation is better than none.  

[10] Cal Advocates commented at the CEC:

The [Final Root Cause Analysis FRCA] finds that the CEC-jurisdictional POUs have PRMs as low as 14%; that they rely on a disproportionately high share of resource adequacy (RA) ‘credits’ with unknown attributes, no must-offer obligation, and no performance penalty or capacity substitution requirements; and that they failed to share the burden of rotating outages when the CAISO issued load shed requests to CPUC-jurisdictional and CEC-jurisdictional LSEs alike on August 14, 2020. 

See The Public Advocates Office’s Comments on Publicly Owned Utility Integrated Resource Plan Guidelines, May 7, 2022 at 3.  Available as TN#245899 at https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=18-IRP-01.

5. Provide any additional comments on the June 14, 2023 stakeholder workshop discussion:

Cal Advocates has no additional comments at this time.

1. Please provide a summary of your organization’s comments on the June 14, 2023 Extended Day-Ahead Market (EDAM) ISO Balancing Authority Area (BAA) Participation Rules stakeholder workshop discussion:

PG&E and other CISO BAA members have been working closely to create consensus on the key elements of Track A1 in order to achieve our common goal of a successful EDAM launch.  Below you will find proposals that are widely supported, feasible, and just and reasonable.

2. Provide your organization’s comments on the initiative tracks and schedule, including interaction with other initiatives, as described in slides 7-8 of the ISO’s presentation:

PG&E appreciates the tight timeline that we are all on.  PG&E shares the CAISO’s goal of a successful EDAM launch.

3. Provide your organization’s comments on the net EDAM export transfer constraint, taking into account the presentations by California Public Utilities Commission Public Advocates Office, San Diego Gas & Electric, Southern California Edison, and ISO staff:

PG&E appreciates the opportunity to comment on the net-export transfer constraint.  PG&E and other CISO BAA members have been working hard to create a consensus perspective and the comments below have wide support.

• The net-export constraint should be in effect all the time not just when applied during stressed conditions.
• The parameter methods and values outlined (below) will only be updated through a process run by the CISO BAA and approved by the CISO BAA members/participants.

Confidence Factor

• The CISO BAA members are proposing a Confidence Factor structure for stressed and non-stress conditions. 
• As CAISO has indicated, and the consensus group agrees, the Confidence Factor should be zero percent (0%) in a stressed conditions.
  • The current stakeholder process or the California Balancing Area Forum should be used to finalize the definition of Stressed Condition as soon as possible.
• The consensus group recommends a low percentage (10%-20%) Confidence Factor during a Non-Stressed Condition for the first year of EDAM deployment to develop data and a substantive set of analysis supporting a change within the EDAM environment.
  • The current stakeholder process or the California Balancing Area Forum should be used to finalize the confidence factor value during non-stressed conditions, concurrently with the definition of Stressed Condition.
  • The percentage should have a periodic re-evaluation.
• The above CAISO-stakeholder efforts can be addressed as part of the California Balancing Area Forum.
  • The effort could include:
    • The CAISO market operator, CISO BAA, and CAISO DMM (Department of Market Monitoring) can present data and recommendations to the CISO BAA members.
    • These data should be related to the CISO BAA reliability, risk of passing/failing WEIM (Western Energy Imbalance Market) RSE (RESOURCE SUFFICIENCY EVALUATION), market efficiency, benefits/costs, or any other metric relevant to changing the value of confidence factor during non-stressed conditions.
    • CISO BAA members decide on any updates.
• The tariff language will identify the construct and plan to develop certain items that do not require a tariff change to facilitate adjusting the percentages.

Preliminary Stress Condition Definition

Stressed conditions will be set based on a list of triggers that include, but not limited to, the following items:

A stressed condition includes all the hours for which condition(s) below are in effect.

• • When the CISO BAA opts into the Emergency Assistance Energy,
  • EEA Watch, Warning, or Emergency is called,
  • Restricted Maintenance Operations,
  • Transmission Emergency,
  • Flex Alert, or
  • If 8-day look-ahead period shows the available RA capacity is unlikely to meet our forecasted demand, reserve requirement, and imbalance reserve requirement.

• The final definition of “Stressed Conditions” will be documented and codified in the business practice manuals after completion of the stakeholder process. 

Reliability Margin

As CAISO has indicated, the consensus group agrees the proposed Reliability Margin outlined by CAISO on 6/14/23 (Slide 17 of the presentation).[1] 

[1]    Slide 17 of the CAISO’s presentation on 6/14/23 accessible here: http://www.caiso.com/InitiativeDocuments/Presentation-ExtendedDay-AheadMarketISOBAAParticipationRules-Jun14-2023.pdf

4. Provide your organization’s comments on solutions for allocating RSE failure surcharges and revenues, taking into account the presentations by Southern California Edison, San Diego Gas & Electric and Six Cities:

Please include your organization’s specific recommendation for an interim solution.

Please include your organization’s specific recommendation for an interim solution.

PG&E appreciates the opportunity to comment on the interim RSE cost allocation method.  PG&E and other CISO BAA members have been working hard to create a consensus perspective and the comments below have wide support among the CISO BAA members.

We suggest an interim two-tiered allocation process.

1. Tier 1 is allocated to LSEs based on their daily deficiency as measured by comparing their modified monthly forward showing (supply stack) to their metered demand.

1. Tier 2 is allocated pro rata to LSE’s based on their metered demand.

Tier 1

Modified monthly forward showing.

The modified monthly forward showing will include:

• The current monthly (forward) RA showing, plus
• An addendum that includes other forward supply that will significantly contribute to the CISO BAA meeting the Day-Ahead RSE.
• To be included on the addendum the supply should meet the following simple criteria.
  1. Not be shown on the standard monthly RA showing.
  2. Be forward contracted for firm power, not curtailable for reliability, and is used to meet (at least) peak hours (as defined by CAISO).
  3. Be expected to contribute towards the RSE for more than half the month (rounding down to the nearest day, i.e., 15 days for months that have 30 or 31 days).
• Examples that should fit these criteria:
  1. RA that is not shown on the plan to cover planned-outage substitution for a short portion of the month.
  2. Forward Energy-only contracts that cover peak periods.
  3. Non-RA contracts that help meet peak demand.

The sum of the standard RA showing, and the addendum supply will be considered the LSE’s total supply contribution meeting the CISO BAA’s RSE. This will be measured against their daily peak metered demand.

Metered Demand and Exports

Tier two should be allocated to metered demand and exports. We understand that the CAISO has been concerned that using metered demand for an interim solution is infeasible due to a mapping issue of LSE-load to SC bid-in-load.  We are not ignoring or trivializing this concern by proposing the use of metered demand.  Our understanding is that this mapping issue is only an issue for approximately 7-10% of total CISO BAA load.[1] We believe there could be workable solutions for this remaining 7-10% and want to work collaboratively with CAISO on finding a workable solution.

Possible solutions:

1. Aggregation: Treat the LSEs that use one SC as one LSE within this cost-allocation. Their supply and load will be aggregated, and they will be allocated costs as if they were all one LSE. They would agree to fixed allocation between those that are aggregated.

2. SC provides split.  While the CAISO may not have visibility of the individual load values, the SC may be able to provide the daily load split for the CAISO to use.

3. Fixed Percentage based on CEC forecasts:  The load scheduled by the SC would be divided up to the LSEs pro rata based on the CEC’s load forecasts. 

Tier 2

Tier 2 is allocated pro rata to LSE’s based on their metered demand.

[1] Per a 6/14/23 email from James Lynn. Our reading of the email suggests 7-10% of the LSE RA load could not be linked to SC load participation.

5. Provide any additional comments on the June 14, 2023 stakeholder workshop discussion:

No further comments

1. Please provide a summary of your organization’s comments on the June 14, 2023 Extended Day-Ahead Market (EDAM) ISO Balancing Authority Area (BAA) Participation Rules stakeholder workshop discussion:

Setting the Confidence Factor

SDG&E supports setting the Confidence Factor (CF) at zero during stressed system conditions and 10% during non-stressed system conditions.

RSE Failure Surcharge/Revenue Allocation

SDG&E supports the methodology presented by SDG&E at the 6-14-23 workshop, with some modifications.

2. Provide your organization’s comments on the initiative tracks and schedule, including interaction with other initiatives, as described in slides 7-8 of the ISO’s presentation:

No comment at this time.

3. Provide your organization’s comments on the net EDAM export transfer constraint, taking into account the presentations by California Public Utilities Commission Public Advocates Office, San Diego Gas & Electric, Southern California Edison, and ISO staff:

SDG&E supports the SCE approach of setting the CF differently during stressed and non-stressed system conditions. During stressed system conditions SDG&E supports setting the CF at zero. This is appropriate because a non-zero CF would put California in the position of accepting non-firm economic imports and firming them up to the level of EDAM transfers, which are considered firm. Even though these economic imports are generally highly reliable, this presents a potential reliability problem where California is “firming up” economic imports for little to no benefit.

During non-stressed system conditions, SDG&E supports setting the CF at 10%. This is an appropriately low number to protect California’s reliability. SDG&E further notes that this does not restrict supply in any way that is inappropriate. Because the CF only applies to economic imports, CAISO is only avoiding a situation where it might otherwise be stuck firming up economic imports to the level of EDAM transfers. Furthermore, in the vast majority of situations, CAISO should have ample excess Resource Adequacy (RA) resources. Under such circumstances, these economic imports are available to the market because the market optimization can schedule any resources that are available to CAISO as EDAM transfers, up to the level of CAISO’s excess RA supply. Therefore, as long as CAISO has excess RA supply, those economic imports are available to the EDAM market. By setting the CF low at 10%, California avoids exporting itself into a reliability situation with no inappropriate consequences to the market.

As for defining “stressed system conditions,” SDG&E recommends any day where CAISO has opted into Assistance Energy Transfers (AET).

4. Provide your organization’s comments on solutions for allocating RSE failure surcharges and revenues, taking into account the presentations by Southern California Edison, San Diego Gas & Electric and Six Cities:

Please include your organization’s specific recommendation for an interim solution.

SDG&E supports a modified version of its own proposal. For surcharges, a two-tiered approach where tier 1 is allocated to LSEs based on their daily deficiency as measured by comparing their modified monthly forward showing (supply stack) to their metered demand, and metered demand should include firm exports. Tier 2 allocates any remaining surcharges to metered demand.

Supply

The modified monthly forward showing should include:

• The current monthly (forward) RA showing, plus
• An addendum that includes other forward supply that meets the following criteria:
  • Not be shown on the standard monthly RA showing.
  • Be forward contracted for firm power and is used to meet (at least) peak hours (as defined by CAISO).
  • Be expected to contribute towards the RSE for more than half the month (rounding down to the nearest day, i.e., 15 days for months that have 30 or 31 days).
  • Some examples that fit these criteria:
    • RA that is not shown on the plan to cover planned-outage substitution for a short portion of the month.
    •  
    • Import contracts that would count for RA if the LSE had the necessary Maximum Import Capability (MIC) allocation.
    • Non-RA contracts that help meet peak demand
  • There should be a requirement to demonstrate that these contracts are as good as RA, but for some technicality.

SDG&E notably breaks with the broader group in that it does not recommend including Energy Only (EO) resources as these resources cannot be counted on to be deliverable to the aggregate of load during stressed system conditions.

Demand

SDG&E proposes to use actual metered demand for each LSE. To the extent that multiple LSEs’ loads may be mixed within the same Scheduling Coordinator (SC), SDG&E understands that this represents no more than 10% of CAISO load and supports any reasonable assumptions or efforts to fairly sub-allocate this demand.

5. Provide any additional comments on the June 14, 2023 stakeholder workshop discussion:

No comment at this time.

1. Please provide a summary of your organization’s comments on the June 14, 2023 Extended Day-Ahead Market (EDAM) ISO Balancing Authority Area (BAA) Participation Rules stakeholder workshop discussion:

With respect to the Net Export Constraint, the Six Cities support: (1) maintaining a Net Export Constraint in effect at all times, (2) setting the Confidence Factor element of the Net Export Constraint (applied to supply that is not eligible to be counted for purposes of Resource Sufficiency Evaluation tests) at 0% during stressed conditions and at 10% during non-stressed conditions, and (3) establishing the Reliability Margin element of the Net Export Constraint as described in Slide 17 of the CAISO’s presentation for the June 14, 2023 workshop.

With respect to allocation of surcharges incurred by the CAISO for failures of the EDAM RSE tests, the Six Cities would support on an interim basis a two-tiered allocation process for RSE failure surcharges, provided that to the maximum extent possible, all supply that would be eligible for purposes of the RSE tests would be considered in calculating supply compared against demand.  Tier 1 allocations would be based on any LSE’s daily deficiency (up to the level of their deficiency) as measured by comparing their modified monthly forward showing (including forward contracted supply eligible to meet RSE requirements, as well as shown RA resources) to their metered demand.  Tier 2 (i.e., remaining surcharge amounts not allocated in Tier 1) would be allocated to LSEs (based on their metered demand) and exports.

It is the Six Cities’ understanding that LSEs representing a substantial portion of CAISO BAA load support the conceptual frameworks outlined below regarding the Net Export Constraint and allocation of surcharges incurred by the CAISO BAA for failures of RSE tests in the EDAM.

2. Provide your organization’s comments on the initiative tracks and schedule, including interaction with other initiatives, as described in slides 7-8 of the ISO’s presentation:

The Six Cities have no comments at this time on the initiative tracks and schedule.

3. Provide your organization’s comments on the net EDAM export transfer constraint, taking into account the presentations by California Public Utilities Commission Public Advocates Office, San Diego Gas & Electric, Southern California Edison, and ISO staff:

The Six Cities support the following framework for Net Export Constraint development and enforcement:

The net-export constraint should be in effect at all times, not just during stressed conditions.

Confidence Factor applicable to non RSE eligible supply:

• The Six Cities support development of different Confidence Factors for stressed and non-stressed conditions.
• The Confidence Factor should be zero percent (0%) in a stressed condition.  The current stakeholder process or the California Balancing Area Forum should be used to finalize the definition of Stressed Condition as soon as possible.
• During non-stressed conditions, the Six Cities recommend a conservative confidence factor (e.g., 10%), for the first year of EDAM deployment to develop data and analysis to evaluate the appropriateness of potential changes to the confidence factor within the EDAM environment.   The current stakeholder process or the California Balancing Area Forum should be used to finalize the confidence factor value to be applied during non-stressed conditions, concurrently with the definition of Stressed Condition.
• The California Balancing Area Forum should include presentations of data and recommendations by the CAISO market operator function, the CAISO BAA operator function, and the CAISO Department of Market Monitoring relating to CAISO BAA reliability, risk of passing/failing WEIM (Western Energy Imbalance Market) RSE tests, market efficiency, benefits/costs, or any other metric relevant to changing the value of the confidence factor during non-stressed conditions.  CAISO BAA market participants should decide on any updates.
• The tariff language should identify the construct and process for evaluating changes to confidence factor percentages but not require a tariff change to adjust the percentages.

On a preliminary basis, the Six Cities support defining stressed conditions as including all hours when any one or more of the following conditions are in effect:

o When the CAISO BAA opts into the potential to receive Emergency Assistance Energy,

o An EEA Watch, Warning, or Emergency is called,

o CAISO declares Restricted Maintenance Operations,

o CAISO identifies a Transmission Emergency,

o CAISO issues a Flex Alert, or

o If CAISO’s 8-day look-ahead anticipates a supply shortage during the look-ahead period.

The final definition of “Stressed Conditions” should be documented in the business practice manuals after completion of the stakeholder process.

The Six Cities support the CAISO’s proposed approach for establishing the Reliability Margin component of the Net Export Constraint as outlined on Slide 17 of the CAISO’s presentation during the 6/14/23 workshop.

4. Provide your organization’s comments on solutions for allocating RSE failure surcharges and revenues, taking into account the presentations by Southern California Edison, San Diego Gas & Electric and Six Cities:

Please include your organization’s specific recommendation for an interim solution.

Conditioned upon recognition, to the maximum extent possible, of all supply that would be eligible for purposes of the RSE tests, the Six Cities would support on an interim basis a two-tiered allocation process for RSE failure surcharges.

Tier 1 would be allocated to LSEs based on their daily deficiency (up to the level of their deficiency) as measured by comparing their modified monthly forward showing (supply stack) to their metered demand.  The modified monthly forward showing should include:

• The current monthly (forward) RA showing, plus
• An addendum that includes other forward supply that will contribute to the CAISO BAA meeting the Day-Ahead RSE.  To be included on the addendum, the supply should meet the following simple criteria.
  1. Not be shown on the standard monthly RA showing.
  2. Be forward contracted for firm power, not curtailable for reliability, and is used to meet (at least) peak hours (as defined by CAISO).
  3. Be expected to contribute towards the RSE for more than half the month (rounding down to the nearest day, i.e., 15 days for months that have 30 or 31 days).
• Examples that should fit these criteria include:
  1. RA that is not shown on the plan to cover planned-outage substitution for a short portion of the month.
  2. Forward Energy-only contracts that cover peak periods.
  3. Non-RA contracts that help meet peak demand.

The sum of the standard RA showing and the addendum supply for each LSE will be considered the LSE’s total supply contribution toward meeting the CAISO BAA’s RSE.  This will be measured against the LSE’s daily peak metered demand.

The Six Cities understand that the CAISO has been concerned that using metered demand for an interim solution is infeasible due to a mapping issue of LSE-load to SC bid-in-load.  Our understanding, however, is that this mapping issue only applies for approximately 7-10% of total CAISO BAA load.  Possible approaches for addressing the 7-10% of “unmapped load” could include:

1. Aggregation: Treat the LSEs that use one SC as one LSE within this cost-allocation.  Their supply and load will be aggregated, and they will be allocated costs as if they were all one LSE.  Entities that are aggregated would agree to a methodology for sub-allocating among themselves.

2. SC provides split.  While the CAISO may not have visibility of the individual load values, the SC may be able to provide the daily load split for the CAISO to use.

3. Fixed Percentage based on CEC forecasts:  The load scheduled by the SC would be apportioned to the LSEs based on the CEC’s load forecasts. 

Tier 2 (i.e., remaining surcharge amounts not allocated in Tier 1) would be allocated to LSEs (based on their metered demand) and exports.

5. Provide any additional comments on the June 14, 2023 stakeholder workshop discussion:

The Six Cities have no additional comments at this time.

1. Please provide a summary of your organization’s comments on the June 14, 2023 Extended Day-Ahead Market (EDAM) ISO Balancing Authority Area (BAA) Participation Rules stakeholder workshop discussion:

SCE appreciates CAISO’s efforts in this initiative by hosting workshops and facilitating discussions among CAISO BAA participants.  SCE’s remains consistent with the proposed positions in the following two areas:

EDAM Net Export Transfer Constraint (NETC)

• The CAISO BAA should not have to firm-up economic imports that become uncurtailable EDAM transfers during stressed conditions.
• The Net Export Transfer Constraint should always be enabled.
• There should be separate confidence factors for stressed and non-stressed conditions:
  • Stressed conditions should have a confidence factor anywhere from 0 to 20%. SCE could support 0%, especially as the new market starts and performance is monitored.
  • Non-stressed conditions should have a confidence factor that is no greater than historical performance data during non-stressed days.
• The CAISO BAA should take a very liberal approach to how stressed conditions are determined.   The following criteria should be used but not limited to:
  • Flex Alert, EEA Watch, Warning or Emergency
  • Restricted Maintenance Operations
  • Transmission Emergency
  • Assistance Energy Transfer opt-in criteria (8-day look-ahead period)
  • 2-day ahead RUC results
  • Excess RA falls below a 1000MW threshold
• After the first year of operation, the CAISO should provide information on how often the constraint was binding, and in what conditions. Based on the information provided by the CAISO, the CAISO, in consultation with stakeholders, may consider adjusting the confidence factor to ensure the reliability of the California BAA grid.

RSE Failure Surcharges and Revenues Allocation

• The CAISO proposal of allocating surcharges pro-rata to metered demand does not incorporate any form of cost causation and enforces zero consequences for causing RSE failures.
• The surcharge allocation should be based on a 2-tiered approach:
  • Tier 1 – LSEs deficient in their monthly RA capacity showing will bear the cost up to their deficient amount.   
    • SCE would support including non-RA contract showings (to offset RA failures) to the extent they are obligated to some form of “must-offer” and if there is an administratively workable way to include them.
  • Tier 2 – Remaining RSE failure deficiency amount gets allocated to all LSEs pro-rata to metered demand + any RSE export obligations

- The RSE revenues allocation should be allocated pro-rata to metered demand.  

2. Provide your organization’s comments on the initiative tracks and schedule, including interaction with other initiatives, as described in slides 7-8 of the ISO’s presentation:

SCE supports CAISO’s proposed initiative tracks and schedules.   SCE appreciates CAISO providing an additional 2 months of stakeholder discussions by seeking CAISO Board approval for September instead of July.   

3. Provide your organization’s comments on the net EDAM export transfer constraint, taking into account the presentations by California Public Utilities Commission Public Advocates Office, San Diego Gas & Electric, Southern California Edison, and ISO staff:

SCE continues to propose having separate confidence factors for stressed and non-stressed conditions.   See SCE’s proposal under question #1. 

SCE's proposal effectively addresses both reliability concerns and EDAM market efficiency. The low/zero confidence factor during stressed conditions ensures that the CAISO BAA reserves adequate supply to respond to reliability events.  However, SCE cautions that to effectively do this, the CAISO will need to take a very relaxed approach in how it determines stressed conditions.   SCE lists several criteria for determining stressed conditions, but any signs of reliability issues should immediately warrant a low confidence factor.  During non-stressed days, the confidence factor should be no higher than historical data performance during non-stressed conditions.  This high confidence factor will allow the market to run efficiently using the “least cost dispatch” principle and will also allow the CAISO BAA to potentially receive EDAM transfer revenues.  

4. Provide your organization’s comments on solutions for allocating RSE failure surcharges and revenues, taking into account the presentations by Southern California Edison, San Diego Gas & Electric and Six Cities:

Please include your organization’s specific recommendation for an interim solution.

SCE continues to propose a 2-tiered RSE failure surcharge structure as an interim allocation mechanism.  See SCE’s proposal under question #1.

SCE understands that some stakeholders have raised concerns about using only monthly Resource Adequacy showings as a proxy for cost causation to calculate Tier 1 failure surcharges.  Some stakeholders suggested also including forward non-RA contracts used to serve peak demand to also be counted.   SCE is open to this suggestion and encourages CAISO to further explore this option if CAISO can verify that the non-RA contracts are RSE eligible supply and are made available to the market, and if it can be implemented quickly enough.  SCE supports further work on the allocation to provide a permanent cost-based allocation.

5. Provide any additional comments on the June 14, 2023 stakeholder workshop discussion:

 SCE does not have any further comments.

1. Please provide a summary of your organization’s comments on the June 14, 2023 Extended Day-Ahead Market (EDAM) ISO Balancing Authority Area (BAA) Participation Rules stakeholder workshop discussion:

Bay Area Municipal Transmission Group (BAMx)^[1] is pleased to submit these comments on the Extended Day-Ahead Market Draft ISO balancing authority area participation rules stakeholder workshop discussion. BAMx supports the consensus proposals developed by a group of California Load Serving Entities for the net EDAM export transfer constraint and for an interim allocation of RSE failure surcharges (Consensus Group Proposals).

[1] BAMx comprises City of Palo Alto Utilities and City of Santa Clara, Silicon Valley Power.

2. Provide your organization’s comments on the initiative tracks and schedule, including interaction with other initiatives, as described in slides 7-8 of the ISO’s presentation:

No comments at this time.

3. Provide your organization’s comments on the net EDAM export transfer constraint, taking into account the presentations by California Public Utilities Commission Public Advocates Office, San Diego Gas & Electric, Southern California Edison, and ISO staff:

BAMx supports the Consensus Group proposal for Net-Export Constraint and Net-Export Constraint Parameters, as described below:

Net-Export Constraint Enforcement

The net-export constraint should be in effect all the time, rather than just when applied during stressed conditions.

Confidence Factor

The Confidence Factor structure should be applied for stressed and non-stressed conditions.  As CAISO has indicated, and the Consensus Group agrees, the Confidence Factor should be zero percent (0%) in a stressed condition. The current stakeholder process or the California Balancing Area Forum should be used to finalize the definition of Stressed Condition as soon as possible (see preliminary definition of stressed conditions below).

The Consensus Group recommends a low Confidence Factor (e.g., 10%-20%) during Non-Stressed Conditions for the first year of EDAM deployment to develop data and a substantive set of analysis supporting a change within the EDAM environment. The current stakeholder process or the California Balancing Area Forum should be used to finalize the confidence factor value during non-stressed conditions, concurrently with the definition of Stressed Condition. The percentage should have a periodic re-evaluation. The CAISO-stakeholder efforts can be addressed as part of the California Balancing Area Forum, with the CAISO market operator, CISO BAA, and CAISO DMM (Department of Market Monitoring) presenting data and recommendations to the CISO BAA members. These data should be related to the CISO BAA reliability, risk of passing/failing WEIM (Western Energy Imbalance Market) RSE (Resource Sufficiency Evaluation), market efficiency, benefits/costs, or any other metric relevant to changing the value of confidence factor during non-stressed conditions. CISO BAA members should decide on any updates. The tariff language will identify the construct and plan to develop certain items that do not require a tariff change to facilitate adjusting the percentages.

Preliminary Stressed Condition Definition

Stressed conditions will be set based on a list of triggers that include, but not limited to, the following items:

A stressed condition includes all the hours for which condition(s) below are in effect.

• When the CISO BAA opts into the Emergency Assistance Energy,
• EEA Watch, Warning, or Emergency is called,
• Restricted Maintenance Operations,Transmission Emergency,
• Flex Alert, or
• If 8-day look-ahead period shows a shortage.

The final definition of “Stressed Conditions” should be documented and codified in the business practice manuals after completion of the stakeholder process.

Reliability Margin

The Consensus Group agrees with the CAISO’s proposed Reliability Margin approach outlined on 6/14/23 (Slide 17 of the presentation).^[1]  

[1]    Slide 17 of the CAISO’s presentation on 6/14/23 accessible here: http://www.caiso.com/InitiativeDocuments/Presentation-ExtendedDay-AheadMarketISOBAAParticipationRules-Jun14-2023.pdf

4. Provide your organization’s comments on solutions for allocating RSE failure surcharges and revenues, taking into account the presentations by Southern California Edison, San Diego Gas & Electric and Six Cities:

Please include your organization’s specific recommendation for an interim solution.

BAMx supports the Consensus Group proposal for an interim RSE Cost Allocation, as described below[1]:

Interim RSE Cost Allocation

Two-tiered allocation process.

• Tier 1 is allocated to LSEs based on their daily deficiency as measured by comparing their modified monthly forward showing (supply stack) to their metered demand.
• Tier 2 is allocated pro rata based on CAISO LSE metered demand and exports.

Tier 1

Modified monthly forward showing.

The modified monthly forward showing should include:

• The current monthly (forward) RA showing, plus
• An addendum that includes other forward supply and demand response resources that will significantly contribute to the CISO BAA meeting the Day-Ahead RSE.
• To be included on the addendum the supply and demand response resources should meet the following simple criteria.
  • Not be shown on the standard monthly RA showing.
  • Be forward contracted for firm power, not curtailable for reliability, and used to meet (at least) peak hours (as defined by CAISO).
  • Be expected to contribute towards the RSE for more than half the month (rounding down to the nearest day, i.e., 15 days for months that have 30 or 31 days).
• Examples that should fit these criteria:
  • RA that is not shown on the plan to cover planned-outage substitution for a short portion of the month.
  • Forward Energy-only contracts that cover peak periods.
  • Non-RA contracts that help meet peak demand.

The sum of the standard RA showing, and the addendum supply and demand response resources will be considered the LSE’s total supply contribution meeting the CISO BAA’s RSE. This will be measured against their daily peak metered demand.

Daily Metered Demand

We understand that the CAISO has been concerned that using metered demand for an interim solution is infeasible due to a mapping issue of LSE-load to SC bid-in-load.  We are not ignoring or trivializing this concern by proposing the use of metered demand.  Our understanding is that this mapping issue is only an issue for approximately 7-10% of total CISO BAA load.^[2] We believe there could be workable solutions for this remaining 7-10% and want to work collaboratively with CAISO on finding a workable solution.

Possible solutions:

1. Aggregation: Treat the LSEs that use one SC as one LSE within this cost-allocation. Their supply and load will be aggregated, and they will be allocated costs as if they were all one LSE. They would agree to fixed allocation between those that are aggregated.

2. SC provides split:  While the CAISO may not have visibility of the individual load values, the SC may be able to provide the daily load split for the CAISO to use.

3. Fixed Percentage based on CEC forecasts:  The load scheduled by the SC would be divided up to the LSEs pro rata based on the CEC’s load forecasts. 

Tier 2

Tier 2 is allocated pro rata based on CAISO LSE metered demand and exports.

[1] For RSE revenue allocation, BAMx supports allocation to CAISO metered load.

[2] Per a 6/14/23 email from James Lynn. Our reading of the email suggests 7-10% of the LSE RA load could not be linked to SC load participation.

5. Provide any additional comments on the June 14, 2023 stakeholder workshop discussion:

  No comments at this time.