Before the Public Utilities Commission of the State of California

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE FILED STATE OF CALIFORNIA 09/09/20 04:59 PM

Order Instituting Rulemaking to Consider Rulemaking 17-07-007 Streamlining Interconnection of Distributed (Filed July 13, 2017) Energy Resources and Improvements to Rule 21.

COMMENTS OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) ON PROPOSED DECISION ADOPTING RECOMMENDATIONS FROM WORKING GROUPS TWO, THREE, AND SUBGROUP

AINSLEY CARRENO Attorney for: SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1358 Facsimile: (626) 302-1935 E-mail: [email protected]

Dated: September 9, 2020

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TABLE OF CONTENTS

I. INTRODUCTION ...... 1

II. DISCUSSION ...... 2

A. Several WG2 and WG3 Proposals Represent a Significant Departure from Current Practices and Merit Additional Implementation Time or Coordination ...... 2

1. SCE Recommends that the Final Decision Order Additional Stakeholder Coordination and a Tier 3 Advice Letter to Implement Proposal A-B 3 and Issue Nine ...... 2

2. Time Should Be Provided for Implementation of Proposal 8m Option B ...... 4

3. Time Should Be Provided for Stakeholder Consultation Prior to Advice Letter Submission Regarding the Lightning Review Process in Issue 11 Proposal B1 ...... 5

B. Issue 12 Timeline Requirements Should Be Clarified or Modified 6

1. Proposal 12a and 12b Timelines Require Clarification ...... 6

2. Time Should Be Provided to Implement Timeline Reporting for Projects Other Than Rule 21 Non-Export .....9

3. Flexibility Should Be Provided in Satisfaction of the Net Generation Output Meter Timeline Set Forth in Proposal 12d...... 9

C. Utilities Should Not Be Required to Provide Data on the “Accuracy” of the Integration Capacity Analysis in Connection with the Resolution of Issue 9 ...... 10

D. Additional Commission Action Is Required Before the Vehicle-to- Grid Alternating Current Working Group Should Commence ...... 11

E. Clarifications or Corrections Are Required to the Proposed Decision ...... 12

1. Proposal 8k Should Not Be Applied to Utilities That Do Not Use PG&E’s Transmission Overvoltage and Transmission Anti-Islanding Tests ...... 12

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2. The Reference to Certification in OP 41 Requires Clarification ...... 13

3. The Adoption of Proposal 23i Should Identify What Qualifies as a “Pilot” and Should Confirm Other Rule 21 Requirements Still Apply ...... 13

4. OP 47 Should Be Updated to Reflect Current Commission Efforts ...... 14

5. The Reference to “UL 1547 SA” in OP 40 Should Be Corrected ...... 14

6. SCE’s Treatment of the Cost-of-Ownership Charge Is Stated Incorrectly ...... 14

III. CONCLUSION ...... 15

APPENDIX A: Southern California Edison Company’s Proposed Modifications to the Proposed Decision

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COMMENTS OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) ON PROPOSED DECISION ADOPTING RECOMMENDATIONS FROM WORKING GROUPS TWO, THREE, AND SUBGROUP

TABLE OF AUTHORITIES

CPUC Rules of Practice and Procedure Rule 14.3 ...... 1 CPUC Resolutions Resolution E-5000 ...... 14 CPUC Rulemaking R.19.09.009 ...... 5

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SUBJECT INDEX OF RECOMMENDED CHANGES

Pursuant to Rule 14.3(b) of the California Public Utilities Commission’s (“Commission”) Rules of Practice and Procedure, Southern California Edison Company (“SCE”) provides the following Subject Index of Recommended Changes in support of its Comments on the Proposed Decision Adopting Recommendations from Working Groups Two, Three, and Subgroup (“PD”). In brief, the Recommended Changes propose to:

 Modify the PD to direct (i) the Energy Division to convene a series of discussions with industry stakeholders within 60 calendar days after issuance of the Final Decision focused on implementing Proposal A-B 3 and Issue 9, as modified by the PD and (ii) the Utilities to submit an implementation plan in a Tier 3 Advice Letter to the Commission within 6 months of issuance of the Final Decision outlining recommendations (as applicable) regarding the standard review, certification requirements, and interconnection processes necessary for implementation of these proposals.

 Allow an implementation period for Proposal 8m Option B of (i) nine months from issuance of the Final Decision for non-fixed solar systems and non-solar technology, and (ii) nine months after the development of necessary tools for fixed solar systems.

 Allow for a 60-day stakeholder consultation period regarding implementation of the Lightning Review Process set forth in Issue 11 Proposal B1 prior to the 180- day period set forth in OP 21, and clarify that the process should “minimize” rather than “remove” the need for engineering technical review.

 Clarify or modify the timelines required to be reported in Proposals 12a and 12b to ensure accurate and consistent reporting and allow for a stakeholder call to discuss necessary clarifications to the dates to be tracked.

 Allow six months for implementation of the reporting requirements set forth in Proposals 12a and 12b as applied to projects other than Rule 21 non-export.

 Modify Proposal 12d to allow 40 business days total for Net Generation Output Meter design and construction (as opposed to 20 business days for design and 20 business days for construction).

 Modify the Advice Letter requirement in OP 15 to require that utilities report on the effectiveness of ICA values by providing data obtained from Proposals 8b and 8c rather than reporting on the “accuracy” of ICA values.

 Delay meetings of the Vehicle-to-Grid Alternating Current Subgroup (V2G AC

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Subgroup) until the Commission issues additional guidance on the standards that should govern V2G AC interconnections and the certification process for V2G AC systems.

 Make several non-substantive clarifications and corrections to the PD, including: (i) clarifying that Proposal 8k does not apply to utilities that do not perform Pacific Gas and Electric Company’s transmission overvoltage and transmission anti-islanding tests; (ii) clarifying the reference to “certification” in OP 41; (iii) clarifying the requirements for pilot programs in Proposal 23i; (iv) updating OP 47 to reflect current Commission efforts; (v) correcting a standard reference in OP 40; and (vi) correcting a misrepresentation of SCE’s treatment of the Cost-of- Ownership charge.

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BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Consider Rulemaking 17-07-007 Streamlining Interconnection of Distributed (Filed July 13, 2017) Energy Resources and Improvements to Rule 21.

COMMENTS OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) ON PROPOSED DECISION ADOPTING RECOMMENDATIONS FROM WORKING GROUPS TWO, THREE, AND SUBGROUP

I. INTRODUCTION

Pursuant to Rule 14.3 of the California Public Utilities Commission’s (the “Commission”) Rules of Practice and Procedure, Southern California Edison Company (“SCE”) respectfully submits these comments on the Proposed Decision entitled “Decision Adopting Recommendations from Working Groups Two, Three, and Subgroup,” which was issued on August 20, 2020 (the “PD”).

SCE appreciates the Commission’s efforts to resolve the issues set forth in Working Group 2 (“WG2”) and Working Group 3 (“WG3”). SCE believes that many of the proposals adopted will help streamline interconnection, improve transparency, and incorporate Integration Capacity Analysis (“ICA”) data into Rule 21. In these comments, SCE recommends modest changes and clarifications to ensure successful implementation and to provide clarity to all stakeholders on the steps to be taken going forward.

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II. DISCUSSION

A. Several WG2 and WG3 Proposals Represent a Significant Departure from Current Practices and Merit Additional Implementation Time or Coordination WG2 and WG3 involved several complex issues. In particular, WG2 included several proposals seeking to incorporate the results of the ICA into Rule 21. The novelty and complexity of these issues led WG2 to request additional time to complete its work.1 While WG2 worked diligently to review all of the proposals and subproposals at issue in the time allotted, in many cases it did not have time to discuss details supporting proposal implementation. Accordingly, SCE’s comments below focus on the critical need to allow stakeholders time to develop proposal implementation plans.

1. SCE Recommends That the Final Decision Order Additional Stakeholder Coordination and a Tier 3 Advice Letter to Implement Proposal A-B 3 and Issue Nine The PD adopts, with modifications, Proposal A-B 3 and the Issue 9 counter proposal, both of which would modify the allowable maximum export levels based on ICA values determined for different times of the year. The PD acknowledges that additional milestones must be met before either Proposal A-B 3 or Issue 9 can be implemented. For Proposal A-B 3, Ordering Paragraph (“OP”) 52 states that a modified Proposal A-B 3 is adopted but shall not be implemented until nine months after technical specifications and standards for Smart Inverter

Phase III (Functions 3 and 8) have been approved by the standards approving bodies. For Issue 9, OP 15 states that implementation cannot occur until a certification scheme for the Limited Generation Profile has been developed and adopted and, within 60 days of adoption of a certification scheme for the Limited Generation Profile, directs SCE, Pacific Gas and Electric Company, and San Diego Gas & Electric Company (collectively, the “Utilities”) to modify the

1 See Motion of the Interstate Renewable Energy Council, Inc. to revise certain deadlines of the R.17-07-007 Scoping Memo (filed July 9, 2018); see also Working Group Two Final Report (filed October 31, 2018) (hereinafter “WG2 Report”) at 4-5 (explaining complexities and reasons for extension).

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Rule 21 Interconnection Application Process to allow a distributed energy resources customer to include a Limited Generation Profile with their application, require the customer to enable generation profile limiting functionality, and allow Utilities the opportunity to alter the profile if warranted. SCE supports the PD’s direction to allow modifications to the maximum export levels and agrees with the PD that there are issues that must be addressed before Proposal A-B and Issue 9 are implemented. While the PD proposes milestones that need to be completed before Proposal A-B and Issue 9 are implemented, it does not provide clear direction as to the stakeholder process that will be utilized to achieve those milestones. SCE is concerned that without such direction, the benefits of Proposal A-B and Issue 9 will not be realized in a timely manner and could result in grid safety and reliability issues. Below are some examples of the complex technical issues that need resolution before Proposal A-B and Issue 9 can be implemented:

 Adoption of a Certification Scheme for Limited Generation Profile Requires an “Owner” - For Issue 9, OP 15 states that implementation cannot occur until a certification scheme for the Limited Generation Profile has been developed and adopted. SCE is not aware of any certification organization (e.g., Underwriters Laboratories (“UL”)) that is developing, or has committed to develop, a certification scheme for a Limited Generation Profile. Linking implementation of Issue 9 to 60 days after the adoption of such certification scheme without having an entity responsible for developing the certification scheme creates an unacceptable level of uncertainty for developers as well as Utilities.

 Function Three Standard in UL 1741 Needs Modification to Allow Exports - Function Three was approved by the Smart Inverter Working Group (“SIWG”) as part of the Smart Inverter Phase 3 advanced functionality and is now incorporated in the UL 1741 standard. However, only static functionality is covered in UL 1741 and therefore it does not currently allow for the limited export functionality called for within Proposal A-B 3. Revisions to the existing UL 1741 standard are required to allow Function Three to accomplish the requirements of OP 52.

 Combined Use of Functions Three and Eight Requires a New Standard - Function Eight currently does not operate as an autonomous function and instead relies on external communication (e.g., from a utility or aggregator). Because Proposal A-B 3 would result in Functions Three and Eight being used in combination, additional standards would need to be developed (such as UL or IEEE).

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 Power Control System (“PCS”) Standard is Needed to Support Proposal A-B 3 – To support the inverter functionality allowed under Proposal A-B 3 a new PCS standard must be developed. A UL PCS standard is currently being updated to incorporate this capability, but it is not expected to be approved and published until 2021 at the earliest. Given the numerous and complex technical implementation issues, SCE urges the Commission to direct the Energy Division to convene a series of discussions with industry stakeholders within 60 calendar days after issuance of the Final Decision focused on implementing Proposal A-B 3 and Issue 9, as modified by the PD. In order to implement the results of the stakeholder discussions, the Final Decision should direct the Utilities to submit an implementation plan in a Tier 3 Advice Letter to the Commission within six months of issuance of the Final Decision outlining recommendations (as applicable) regarding the standard review, certification requirements, and interconnection processes necessary for implementation of these proposals. Stakeholders would be able to utilize the standard Tier 3 Advice Letter process to raise any concerns with the implementation plan.

2. Time Should Be Provided for Implementation of Proposal 8m Option B

SCE respectfully requests that the Commission modify its adoption of Proposal 8m

Option B to allow time for implementation. As indicated in the WG2 Report,2 there are several areas that need to be developed in the Application Submittal Process for successful implementation of this process including:

(1) Determination of what additional information customers must specify in the interconnection request so that SCE can use PV Watts or an equivalent tool to generate the best-case production output profile;

(2) Determination of what tool can be used or what tool needs to be created to generate the best-case generation profiles. As indicated the WG2 Report,3 PV Watts will require adjustments to generate a best-case production output profile. The current PV Watts tool generates typical output values accounting for historical weather, which may provide output values not indicative of actual production. Given that PV Watts is owned by the National Renewable Energy Laboratory (“NREL”) and SCE does not have the ability to

2 See WG2 Report at 68-69. 3 See id. at 69.

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change that tool, alternative methods may need to be researched, tested, and deployed prior to deploying this option.

(3) Coordination of Proposal 9, Proposal A-B 3, and Proposal 8m. That is, projects that are interconnected under these proposals need to be coordinated to address issues such as which project type takes priority for capacity that may be available in the ICA calculations. For non-solar fixed systems/technology (e.g., storage, synchronous, induction), no additional tools are required to implement Proposal 8m Option B as these projects will be reviewed based on nameplate rating consistent with current practice. However, SCE needs time to adjust its study process documents, training materials, and tracking tools to align with the new requirements of Proposal 8m. SCE therefore proposes the following timeline for implementation of Proposal 8m Option B to allow for profile development:

For non-fixed solar systems or non-solar technology (full nameplate): Nine months from Final Decision.

For fixed solar systems for which new tools need to be developed: Nine months after the development of the necessary tools. It should be noted that if PV Watts is used, then funding may be required for NREL to update its PV Watts tool or for other parties to develop new tools. If a tool to generate the best case fixed PV output profile is unable to be updated (in the case of PV Watts) or a new tool developed within six months from issuance of a Final Decision, SCE will provide the Commission with an estimated timeline for development no later than six months from the issuance of the Final Decision.

3. Time Should Be Provided for Stakeholder Consultation Prior to Advice Letter Submission Regarding the Lightning Review Process in Issue 11 Proposal B1 SCE is supportive of the concept of a “Lightning Review Process” and has begun to implement process improvements that support the Commission’s governing principles as set forth in OP 20, including the use of single line diagram templates as provided under the Microgrid Rulemaking (R.19.09.009) and other improvements such as “frontloading.” SCE recommends, however, that principle (iii) for developing enhancements for streamlining and the

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Lightning Review Process be clarified to state that the Utilities should “minimize” the need for engineering technical review rather than “remove” it. In many cases, there is a need for engineers to review the technical documentation and provide technical guidance depending on the complexity of the project and the experience of the document reviewer. SCE also believes the Advice Letter process would benefit from an additional 60-day period for stakeholder outreach prior to the 180-day period set forth in OP 21 as this process was not discussed in great length within the working group. SCE believes this initial period of stakeholder consultation will support Advice Letter development and prevent protests and misunderstandings later in the process. B. Issue 12 Timeline Requirements Should Be Clarified or Modified

1. Proposal 12a and 12b Timelines Require Clarification As evidenced by SCE’s voluntary reporting of timelines as proposed within WG3 Proposal 12a for non-export projects prior to issuance of a Commission decision, SCE is supportive of additional timeline tracking for purposes of providing baseline data and review as appropriate. However, SCE objects to the addition of certain non-consensus timelines set forth

in Proposal 12b4 because they encompass multiple steps that must be aggregated into the overall timeline. For example, for the non-export timelines on which SCE has been voluntarily reporting, SCE reports on 47 discrete data points or date fields. Most of the required data points that would be needed to report on the timelines in Proposal 12b do not exist in SCE’s databases at this time and will need to be tracked manually. Moreover, for certain timelines there is ambiguity about the start and end date that must be clarified to ensure accurate reporting. Nonetheless, should the Commission elect to adopt the 19 timelines set forth in Proposals 12a and 12b, SCE provides the following requests for clarification or modification:

a) Time from submission of Interconnection Request to the utility’s acknowledgement of receipt: No comments.

4 See Working Group Three Final Report (filed June 14, 2019) (hereinafter “WG3 Report”) at 10, 14, 15-16.

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b) Time from submission of Interconnection Request to time deemed complete: SCE notes that this step often requires the clearing of deficiencies by the Interconnection Customer. In SCE’s current voluntary reporting it separates out the various rounds of deficiencies to include only time that SCE controls. SCE asks that the Commission apply this same approach to the reporting required by Proposal 12a.

c) Time from Interconnection Request deemed complete to completion of initial review and provision of results: SCE proposes that this language be adjusted to set a specific end date (issuance of Initial Review results/report). d) Time from Supplemental Review start date to completion of Supplemental Review: SCE requests that the Commission acknowledge that this step is not required if the project successfully passes Initial Review. SCE also proposes that this language be adjusted to set a specific end date (issuance of Supplemental Review results/report).

e) Time from Electrical Interdependence Test start date to its completion: SCE requests that the Commission acknowledge that this step is not required if the project successfully passes Initial Review or Supplemental Review. SCE also proposes that this language be adjusted to set a specific end date (issuance of Electrical Interdependence Test results/report).

f) Time from Electrical Interdependence Test completion to Electrical Interdependence Test results scoping meeting held: SCE requests that the Commission acknowledge that this step is not required if the project successfully passes Initial Review or Supplemental Review. SCE also believes that the language of this timeline should say “Time from Electrical Interdependence Test results/report issuance to Detailed Study Scoping Meeting.”

g) Time from study scoping meeting until study agreement provided: SCE requests that the Commission acknowledge that this step is not required if the project successfully passes Initial Review or Supplemental Review.

h) Time from System Impact Study start date to its completion date: SCE requests that the Commission acknowledge that this step is not required if the project successfully passes Initial Review or Supplemental Review.

i) Time to provide Draft Generator Interconnection Agreement applicable milestone: SCE requests clarification on the start date for this timeline. SCE proposes that there be an individual timeline provided for each path (Initial Review, Supplemental Review, Detailed Study).

j) Time from Draft Generator Interconnection Agreement provided or Final Study Report date for Detailed Study to date Generator Interconnection Agreement executed: SCE proposes that this timeline state “Time from issuance of Draft Generator interconnection Agreement to date Generator Interconnection Agreement executed.”

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SCE also notes that the time required to complete negotiations and execute an interconnection agreement depends on both the Utility and the Interconnection Customer. Accordingly, this timeline should be provided for informational purposes only. k) Time from when the customer notifies the utility it has completed all of its obligations under the agreements (F.5.b) including commissioning tests, to when the utility provides the customer Permission to Operate: SCE requests clarification on the start date of this timeline as the time “when the customer notifies the utility it has completed all of its obligations under the agreements” does not exist or is not defined in Rule 21 today. SCE proposes instead that this timeline begin when the utility performs the commissioning test and/or technically approves the generating facility. l) Total time from submission of Interconnection Request to Permission to Operate: No comments. m) Time from request to consider modification to determination whether modification is material: SCE requests that the Commission acknowledge that this timeline is applicable only to projects that request a material modification analysis, and that there is no limit as to how many material modification requests a project may request, leading to some projects having multiple iterations of this timeline. n) Time for responding to line-side taps variance requests (for Utilities that require a variance request): No comments (SCE does not request line-side tap variances). o) Design and invoice of net generation output meter: SCE requests that the Commission acknowledge that this is a multi-step timeline and may include utility time as well as third party or customer time. p) Installation of net generation output meter: SCE requests that the Commission acknowledge that this is a multi-step timeline and may include utility time as well as third party or customer time. q) Time from customer agreement to proceed to final design and issuance of invoice: There are two possible end points to this multi-step timeline. SCE recommends splitting the timeline into (1) the start of design phase and completion of design phase, and (2) the start of the invoice phase and the submittal of the invoice. r) Time from customer payment of invoice and completion of customer work to completion of upgrade construction: SCE recommends a change to the timeline wording to include the start of construction phase and end of construction phase. s) Time for scheduling of Commissioning Test: The performance of the Commissioning Test is a more important milestone than the scheduling of the Commissioning Test. Moreover, the scheduling of the Commissioning Test is only a single point in time, not a timeline. SCE therefore recommends that the language of this

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timeline be modified to “time from scheduling of the Commissioning Test to performance of the Commissioning Test.” SCE also supports a stakeholder call to discuss the necessary clarifications described above.

2. Time Should Be Provided to Implement Timeline Reporting for Projects Other Than Rule 21 Non-Export

Consistent with SCE’s WG3 comments,5 SCE respectfully requests the Commission to allow for a phased approach for project reporting beyond non-exporting projects. SCE has been voluntarily reporting on a set list of timelines for non-export projects since July of 2019. SCE selected non-export projects because they represent the highest volume of its non-NEM Rule 21 interconnection requests. Additionally, SCE chose non-export projects because SCE is able to take advantage of its GIPT system to create this reporting, which currently only processes Rule

21 non-export projects. 6 SCE therefore requests that the Commission provide six months from issuance of the Final Decision to commence reporting for projects other than non-export to allow SCE to develop a methodology to track these projects.

3. Flexibility Should Be Provided in Satisfaction of the Net Generation Output Meter Timeline Set Forth in Proposal 12d SCE requests that the CPUC consider that the “design” phase and the “construction” phase of Net Generation Output Meters (NGOM) may not be of equal length. Accordingly, SCE proposes that Proposal 12d be adjusted to allow 40 business days total for NGOM design and construction. SCE believes that this will allow the Utilities to manage their business processes while still achieving stakeholders’ desired 40-business day timeline for NGOM design and construction.

5 WG 3 Report at 22 (“Initial reporting by SCE, to start in August 2019, will include Rule 21 non- exporting projects, with the remaining Rule 21 interconnection request types included for reporting and tracking as SCE’s new database is built to support those new types of interconnection requests.”). 6 See id.

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C. Utilities Should Not Be Required to Provide Data on the “Accuracy” of the Integration Capacity Analysis in Connection with the Resolution of Issue 9 SCE proposes a modification to the Advice Letter requirement set forth in OP 15 given that the 20 percent buffer is not related to “accuracy.” The 20 percent buffer is instead caused by the need for system flexibility and the need to account for operational flexibility due to operational switching, load reduction and increased generation. The 20 percent buffer is in support of grid safety and reliability to allow for real time distribution operations, not due to inaccuracy of ICA calculations. Accordingly, continued use of the 20 percent buffer would depend on the continued need for this level of system and operational flexibility rather than the accuracy of the ICA values. Moreover, it is not a straightforward task for the Utilities to provide data on the accuracy of the ICA values. The concept of ICA “accuracy” was heavily discussed within the ICA Working Group (“ICA WG”) as part of Distribution Resources Plan (“DRP”) Demonstration Project A. In the ICA WG, the concept of determining ICA accuracy was addressed by having the Utilities perform independent ICA calculations on the publicly available IEEE 123-node feeder. The Utilities compared data from two different power flow tools (CYME and Synergy) to verify that each tool was calculating equivalent data. This comparative analysis information can be found in SCE’s Updated Demonstration Projects A and B Final Reports.7 The comparative analysis showed that different power flow tools generate equivalent ICA values and therefore the ICA methodology as outlined in the ICA WG Report and SCE Demonstration Project A produce ICA values that can be used for the interconnection use case. Accordingly, ICA accuracy cannot be easily evaluated. For example, to determine if an ICA value is accurate, a utility would be required to install generation at a given location, install instrumentation sensing devices (voltage and power sensing), then take data from those sensing

7Southern California Edison Company’s Updated Demonstration Projects A and B Final Reports, dated Jan. 4, 2017, R.14-08-013, at 49, available at http://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/FB6E204FF178F2D08825809F0006734B/$FILE/R1 408013-SCE%20Updated%20Demo%20Projects%20A%20and%20B%20Final%20Reports.pdf.

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devices to compare to the output of the ICA values. This complexity led the ICA WG to rely on the comparative analysis to accept and recommend the ICA methodology. The ICA WG acknowledged that once ICA is implemented through Rule 21 changes, opportunities to evaluate the ICA data would be done through monitoring of interconnection projects. Therefore, SCE recommends that the Utilities provide data obtained from Proposals 8b and 8c in the Advice Letter to evaluate the effectiveness of the ICA values. For this reason, and because the accuracy of ICA values is not relevant to the continued use of the buffer, SCE proposes removing the requirement for utilities to provide data on the accuracy of the ICA.

D. Additional Commission Action Is Required Before the Vehicle-to-Grid Alternating Current Working Group Should Commence SCE was an active participant within the Vehicle-to-Grid Alternating Current (“V2G AC”) Subgroup and is supportive of these critical discussions to advance standards and interconnection processes for bi-directional Plug-in Electric Vehicles (“PEVs”). However, as discussed within the V2G AC Working Group Report, there are complexities of this technology that would benefit from additional Commission guidance. The V2G AC Working Group was established by the California Energy and Storage Association (“CESA”) in recognition of the fact that involvement was required by non-utility parties with expertise related to automobile standards. The V2G AC Working Group engaged in detailed technical evaluation of all existing standards to determine if existing standards could fulfill the need to interconnect V2G AC technology to the grid. The V2G AC working group identified eight critical gaps related to reconcilement of automobile (SAE J3072) and UL “traditional” Rule 21 stationary inverter governing standards (UL 1741, IEEE1547) that need to

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be addressed to allow V2G AC systems to be interconnected to the grid.8 In particular, Commission guidance is needed on the following issues:

What actual standard should govern V2G AC systems? Two options for this topic have been discussed without resolution:

1. Utilize SAE J3072 for the onboard inverter and related equipment and potentially utilize UL 9741 for the stationary interface; or

2. Utilize UL standard (such as UL1741 or UL 9741) as a single standard for V2G- AC systems.

What equipment certification procedures should be mandated for V2G-AC systems (and what processes would govern to allow V2G-AC systems to discharge)? Two options for this topic have been discussed without resolution:

1. Require that V2G-AC inverters or inverter systems be certified by an OSHA approved NRTL equivalent to all other inverters that are connected to the grid. SCE has supported and continues to support this option; or

2. Allow the automotive industry to self-certify their equipment. SCE highlights the V2G AC Working Group background and key unanswered questions to demonstrate that the V2G AC Working Group will be unable to move forward without Commission resolution of these questions. Accordingly, SCE requests that the Commission delay commencement of the Utility-led working group until the Commission issues further guidance on governing standards and certification processes. E. Clarifications or Corrections Are Required to the Proposed Decision

1. Proposal 8k Should Not Be Applied to Utilities That Do Not Use PG&E’s Transmission Overvoltage and Transmission Anti-Islanding Tests OP 8 subsection (b) directs the Utilities to “revise the language in Screen L to require SDG&E and SCE to publish a guidance document, similar to that used by PG&E, identifying the specific screening approach to be used by SCE and SDG&E.” As discussed within WG2 and most recently within Working Group Four (“WG4”) discussions on Issue 18, SCE does not now

8 See Final Report of the Vehicle to Grid Alternating Current Interconnection Subgroup (filed December 11, 2019).

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or intend to at this time perform enhanced anti-islanding screening similar to that employed by

PG&E.9 SCE does not anticipate considering potential revisions (if any) to Screen L until a final decision is issued in WG4 and after ongoing review underway as part of an Electric Program Investment Charge (“EPIC”) study is completed. Therefore, consistent with the approach taken

in WG4 Proposals 18a, 18b, 18c, and 18e,10 additional requirements regarding enhanced anti- islanding screening should not be placed on utilities that do not perform such screenings. This modification aligns with IREC’s intent in Option C, as Option C contemplated that SCE and SDG&E would publish a guidance document only if they determine that it is necessary to screen

for anti-islanding prior to the Issue 18 discussion.11 2. The Reference to Certification in OP 41 Requires Clarification

SCE believes clarification is necessary as to what certification is referred to within the OP 41 clause “upon certifying.” Based upon WG3 discussions, the only way to satisfy the certification requirement is to be certified under UL Power Control Systems and 1741 SA.12 SCE therefore proposes to modify the language of OP 41 to align with the intent of Proposal 23d.

3. The Adoption of Proposal 23i Should Identify What Qualifies as a “Pilot” and Should Confirm Other Rule 21 Requirements Still Apply SCE supports proposal 23i but wishes to confirm that although projects that qualify as pilots would be exempt during a transition period from Rule 21 Section Hh advanced “Smart Inverter” requirements, such projects remain subject to legacy inverter requirements located in

9 See WG 2 Report at 57; Working Group 4 Final Report (filed August 12, 2020) (hereinafter “WG 4 Report”) at 17. 10 See WG 4 Report at 18. 11 See WG2 Report at 63 (“SCE and SDG&E currently do not screen for anti-islanding, but should they determine it is necessary in their opinion to do so prior to the Issue 18 discussion, this proposal would allow this so long as they publish a guidance document, similar to PG&E’s, that identifies the specific screening approach they intend to use.”). 12 See WG 3 Report at 70 (noting that systems must meet pre-defined criteria, including “UL Power Control Systems CRD (UL CRD) and UL 1741 SA certification testing, which will demonstrate that: (1) the EV will not discharge if the EVSE is set to unidirectional mode; (2) the EVSE will not inadvertently change to bidirectional mode; and (3) that factory default settings are set to unidirectional mode”).

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Section H and Section L along with related certification requirements and other non-inverter related Rule 21 requirements. SCE outlines its proposed clarification in Appendix A. SCE also believes there is a need to define which projects qualify as “pilots” to provide clear guidance to Utilities and stakeholders. SCE proposes that pilots be defined as those projects that have received funding from the California Energy Commission or approved EPIC projects with interconnection requests dated no later than December 31, 2020.

4. OP 47 Should Be Updated to Reflect Current Commission Efforts Commission directed efforts are underway in accordance with Resolution E-5000 requirements to update the Rule 21 tariff with updated IEEE 1547 and 1547.1 standards. OP 47 should therefore be updated to reflect these efforts currently underway by removing the reference to accounting for IEEE 1547 and IEEE 1547.1 updated requirements and the requirement to file an Advice Letter implementing those changes. 5. The Reference to “UL 1547 SA” in OP 40 Should Be Corrected

SCE believes the reference to “UL 1547 SA” in OP 40 is intended to refer to “UL 1741 SA.” Moreover, since Issue 23(c) was developed IEEE 1547 and EEE 1547.1 have been updated with new requirements and are now referred to as UL 1741 SB. SCE therefore recommends correcting the error and striking the “SA” (i.e., replacing “UL 1547 SA” with “UL 1741”). 6. SCE’s Treatment of the Cost-of-Ownership Charge Is Stated Incorrectly

On page 124 of the PD, the Commission states that “…all three Utilities oppose separating the replacement charge from the cost-of-ownership charge.” SCE clarifies that it is not opposed to separating charges associated with replacement coverage for Added/Interconnection Facilities. SCE currently provides customers the option to choose

Added/Interconnection Facilities with or without replacement coverage.13 Accordingly, SCE requests to correct the statement regarding SCE’s opposition to separating replacement charge from the cost-of-ownership.

13 See SCE Rule 2, Section H.

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III. CONCLUSION SCE appreciates the opportunity to provide these comments and encourages the

Commission to accept the PD with the proposed modifications described above and as listed in

Appendix A.

Respectfully submitted,

AINSLEY CARRENO

/s/ Ainsley Carreno By: Ainsley Carreno

Attorney for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1358 Facsimile: (626) 302-1935 E-mail: [email protected]

Dated: September 9, 2020

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Appendix A Southern California Edison Company’s Proposed Modifications to the Proposed Decision

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Southern California Edison Company’s Proposed Modifications to the Proposed Decision

Proposed text deletions are in bold and strikethrough (abcd)

Proposed text additions are in bold and underlined (abcd)

Reference Proposed Modifications FoF 3 The Integration Capacity Analysis provides an estimation about the size of a project that can be interconnected at a specific point in a circuit and not require significant distribution upgrades. FoF 18 Synchronous or induction generators cannot use the Integration Capacity Analysis (ICA) values directly given that ICA to determine a specific value and are automatically assignsed a value of 1.2 per unit short circuit contribution, which is only applicable to inverter-based generators. FoF 19 Proposal 8f1 would add Screen F1 to the interconnection process, which would allow non-inverter based generators to use the calculated ICA values. determine whether the generating system’s short circuit contribution exceeds 1.2 per unit. FoF 21 Existing tariff language allows generating facilities with a Gross Rating of 11 kVA or less to bypass Screens K, L, and M. F, G, H, and J. FoF 36 The proposed language from IREC would require a guidance document to be published identifying the specific screening approach SCE and SDG&E would use should they determine that it is necessary in their opinion to do so prior to Issue 18 discussion. FoF 69 A final buffer for resolving Issue 9 should be based on real-world tests of the Integration Capacity Analysis grid operating conditions which may change at any moment impacting safety and reliability if not properly planned. FoF 70 An interim 20 percent buffer for the Issue 9 proposal will ensure the safety and reliability of the grid while we gather data on the accuracy efficacy of the Integration Capacity Analysis values. FoF 71 Eighteen months after implementation of the Issue 9 proposal should provide adequate data collection on the accuracy adequacy of the Integration Capacity Analysis values by relying on reporting from Proposals 8b and 8c. FoF 117 The Working Group Two report proposes four principles for developing enhancements for streamlining and the Lightning Review process which were not fully discussed in the Working Group. to which no party expressed opposition. FoF 197 The existing Rule 21 tariff allows V2G DC EVSE systems to be interconnected if the EVSE meets all Rule 21 requirements, including applicable UL 1741 SA certification requirements. FoF 252 Proposal A-B 3 would allow an inverter approved for non-export and limited export to be set using different maximum export value settings at

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different times of the year, when meeting the qualifications of Proposal A- B 1 or A-B 2. FoF 253 Smart Inverter Phase III Function 8 may enables systems to have different export values at different parts of the year and can vary seasonally, monthly, or hourly., but is unproven and requires further evaluation. FoF 254 Standards to test control systems to enable operations for proposal A-B #3 are unproven and are not approved at this time FoF 261 There is a need for further guidance on the applicability of interconnection standards to V2G AC. value in holding a meeting of the subgroup on a routine basis to provide the members of the subgroup with news on the status of the V2G AC Interconnection standards. FoF 263 V2G AC interconnection standards need to be developed and adopted prior to the Commission considering the jurisdictional question of plug-in electric vehicle equipment requirements or including self- certification requirements for interconnection policy issues. CoL 2 Proposal 8b should be adopted with the clarification that Southern California Edison Company, Pacific Gas and Electric Company, and San Diego Gas & Electric Company shall not be required to perform additional Integration Capacity Analysis for projects with less than 30 kilovolt amperes nameplate capacity. Proposal 8b shall also require Southern California Edison Company to develop a cost estimate for flagging when ICA values are likely to be updated in the upcoming month. CoL 19 The Utilities’ counter proposal to resolve Issue 9, with the modification to allow monthly customer changes, should be adopted. Additional technical implementation requirements should be discussed with affected industry stakeholders. CoL 30 The concept of the Lightning Review process recommended in Proposal B1 for Issue 11 should be adopted. Additional technical and process implementation requirements should be discussed with affected industry stakeholders. CoL 31 The four principles for developing the Lightning Review process should be adopted. Additional technical and process implementation requirements should be discussed with affected industry stakeholders. CoL 40 Proposal 12b should be adopted with modifications. CoL 41 Proposal 12d should be adopted modified to establish a 40-business day timeline for the design and construction of net generation output meters. CoL 57 Rule 21 should specifically state that V2G DC EVSE systems may be interconnected if the EVSE meets all Rule 21 requirements, including applicable UL 1741 SA certification requirements. CoL 68 Proposal 27a should be adopted with the modification to not require Rule 21 to be updated to IEEE1547-2018 given that those efforts are already under way based on Resolution E-5000.

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CoL 72 Proposal A-B 3 should be modified to allow for additional stakeholder coordination and to require Utilities to wait for control system testing standards to be approved. CoL 75 Utilities should host a meeting of the V2G AC Subgroup or V2G AC industry stakeholders on a routine basis to update the members of the subgroup on the status of V2G AC interconnection standards after the Commission issues guidance on which interconnection standards should govern and how V2G-AC equipment should be certified. OP 2 Proposal 8b is adopted. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (Utilities) shall use the Initial Review process to determine if Integration Capacity Analysis values at the proposed Point of Interconnection need to be updated using the Integration Capacity Analysis tool on the specific electrical node into the Initial Review process or running the Integration Capacity Analysis on all the electrical nodes in the circuit. Utilities shall not perform additional Integration Capacity analyses as part of the interconnection process of projects with less than 30 kilovolt amperes nameplate capacity. Utilities shall share the results of any Integration Capacity Analysis updates with the interconnecting generator and provide an explanation of changes to grid conditions or the interconnection queue. Utilities shall comply with confidentiality provisions and data reduction policies. OP 5 Proposal 8f1 is adopted. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company shall include a new Screen in the Interconnection Rule 21 process, to be named Screen F1, which will determine whether a generating system’s short circuit contribution exceeds 1.2 per unit be used to evaluate non- inverter based generation with ICA values. OP 8 Option C of Proposal 8k is adopted on an interim basis until resolution of Issue 18 in Working Group Four for utilities which apply the requirements outlined in Proposal 8k. Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), and Southern California Edison Company (SCE) shall: a) modify Screen L in Interconnection Rule 21 to include the transmission overvoltage and transmission anti-islanding tests currently in Screen M if studies as outlined in Proposal 8k are required; and b) revise the language in Screen L to require SDG&E and SCE to publish a guidance document similar to that used by PG&E, identifying the specific screening approach to be used by SCE and SDG&E if SCE or SDG&E requires transmission overvoltage and transmission anti-islanding tests in the future. OP 11 Option B of Proposal 8m is adopted with modification. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (Utilities) shall apply a 10 percent buffer to the Integration Capacity Analysis-Static Grid profile and to the Integration

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Capacity Analysis-Operational Flexibility profile during review of Screen M of the Rule 21 Interconnection Application Process. Utilities shall implement this proposal (i) nine months from the issuance of this decision for non-fixed solar systems or non-solar technology; and (ii) nine months after the development of necessary tools to generate the best-case production output profile for fixed solar systems. If the necessary tools for (ii) are not developed within six months of the issuance of this decision, Southern California Edison Company shall provide the Commission with an estimated timeline for development no later than six months from the issuance of this decision. If there are costs to develop these tools Southern California Edison Company will develop a proposal and submit testimony in the same manner as set forth in OP 10. OP 12 Proposal 8n is adopted. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company shall update Screen N or applicable Supplemental Review screen of the Rule 21 Interconnection Application Process to account for thermal overload, overvoltage conditions and protection while adjusting for the following three scenarios: i) when the Interconnection Request is below the updated Integration Capacity Analysis value and passes Screen F1; ii) when the Interconnection Request is above the updated Integration Capacity Analysis value or fails Screen F1; and iii) when Integration Capacity Analysis information is not available. OP 13 Proposal 8q is adopted. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company shall update Screen P or applicable Supplemental Review Screen of the Rule 21 Interconnection Application Process to account for new smart inverter capabilities. OP 15 The counter proposal from Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (Utilities) to resolve Issue 9 is adopted with modification. Within 60 days of after technical specifications and standards for Smart Inverter Phase III (Functions 3 and 8) or the Underwriters Laboratories’ Power Control System have been approved and published by the standards approving bodies or adoption of a certification scheme for to enable the Limited Generation Profile, Utilities shall modify the Rule 21 Interconnection Application Process to allow a distributed energy resources customer to include a Limited Generation Profile with their application, require the customer to enable generation profile limiting functionality, and allow Utilities opportunity to alter the profile if circumstances warrant it. As part of the proposal, Utilities shall: i) allow customers to utilize a smart inverter’s ability to increase its output on a monthly basis; and ii) use a 20 percent buffer, which shall be revisited. Within 60 days of the issuance of this decision, the Energy Division shall convene a series of stakeholder discussions focused on implementing the proposal. Within six months of issuance of this

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decision the Utilities shall submit a Tier 3 Advice Letter outlining recommendations (as applicable) regarding the standard review, certification requirements, and interconnection processes necessary for implementation of the proposal. No later than 18 months after the implementation of this proposal, Utilities shall submit a Tier 3 Advice Letter providing data on the accuracy of the Integration Capacity Analysis and addressing whether the Commission should continue use of the 20 percent buffer or decrease it based on the data. Data obtained from Proposals 8b and 8c can be used to evaluate the effectiveness of the ICA values on the interconnection process. OP 20 The following four principles for developing enhancements for streamlining and the Lightning Review Process are adopted: i) design for the most common cases; ii) minimize roundtrips between utility and applicants by frontloading information exchange; iii) remove minimize the need for engineering technical review by using a checkbox or lookup verification; and iv) create standard templates for required documents. OP 21 Within 60 days of the issuance of this decision, Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (Utilities) shall conduct stakeholder outreach regarding implementation of the Lightning Review Process. Within 180 days of the completion of the 60-day stakeholder outreach period issuance of this decision, Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company the Utilities shall submit a Tier 3 Advice Letter providing a detailed proposal for implementation of the Lightning Review Process, in compliance with the principles adopted in Ordering Paragraph 20, and in consideration of the positions described in the Working Group Two Report. OP 23 Proposals 12a and 12b are adopted, with modifications. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (Utilities) shall track the 19 timelines listed below, beginning 90 days from the issuance of this decision for Rule 21 non-export projects and beginning six months from the issuance of this decision for other project types. No later than 120 days from the issuance of this decision, and once every quarter thereafter, Utilities shall provide the results of tracking to the Director of the Energy Division and the service list for this proceeding, or its successor. a) Time from submission of Interconnection Request to utility’s acknowledgement of receipt; b) Time from submission of Interconnection Request to time deemed complete, to be reported as the following sub-steps; a. Time from utility’s acknowledgement of receipt to notice of first deficiency (if any); i. (if none) Time from utility’s acknowledgement of receipt to notice of deemed complete;

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b. Time from receipt of cure of first deficiency to notice of second deficiency (if any); i. (if none) Time from receipt of cure of first deficiency to notice of deemed complete; 1. Time from receipt of cure of second deficiency to notice of deemed complete; c) Time from Interconnection Request deemed complete to issuance of Initial Review results/report completion of initial review and provision of results; d) Time from Supplemental Review start date to completion issuance of Supplemental Review results/report (if Supplemental Review required); e) Time from Electrical Interdependence Test start date to its completion issuance of Electrical Interdependence Test results/report (if Electrical Interdependence Test required); f) Time from Electrical Interdependence Test completion results/report issuance to Electrical Interdependence Test Detailed Study results sScoping mMeetingheld (if Detailed Study required); g) Time from Detailed sStudy scoping meeting until study agreement provided (if Detailed Study required); h) Time from System Impact Study start date to System Impact Study results/report issuance (if Detailed Study required) its completion date; i) Time to provide Draft Generator Interconnection Agreement applicable milestone, to be reported as follows for the applicable study path: a. Time from issuance of successful Initial Review results/report issuance to draft Generator Interconnection Agreement issuance; or b. Time from issuance of successful Supplemental Review results/report to draft Generator Interconnection Agreement issuance; or c. Time from issuance of Facilities Study (or alternatively, a combined System Impact Study and Facilities Study) to draft Generator Interconnection Agreement issuance; j) Time from issuance of Draft Generator Interconnection Agreement provided or Final Study Report date for Detailed Study to date Generator Interconnection Agreement executed (timeline is for information only, as includes both utility and customer time); k) Time from when the utility performs commissioning test and/or technically approves the generating facility the customer notifies the utility it has completed all of its obligations under the agreements (F.5.b) including commissioning tests, to when the utility provides the customer Permission to Operate;

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l) Total time from submission of Interconnection Request to Permission to Operate (Not in Rule 21, tracked for informational purposes.) m) Time from request to consider modification to determination whether modification is material (F.3.b.v) (As applicable. Projects are not limited to the number of material modification requests, so each project may have multiple iterations of this timeline); n) Time for responding to line-side taps variance requests (for Utilities that require a variance request); o) Design and invoice of net generation output meter (timeline is for information only, as includes both utility and customer and/or third party time); p) Installation of net generation output meter (timeline is for information only, as includes both utility and customer and/or third party time); q) Time from customer agreement to proceed to final design and issuance of invoice, to be reported as two timelines; a. Time from commencement of design phase to completion of design phase; and b. Time from invoice phase commencement to completion of invoice phase; r) Time from customer payment of invoice and completion of customer work to completion of upgrade construction, to be reported as two timelines: a. Time from customer payment of invoice and start of construction (as applicable); and b. Time from start of construction to notice of completion of construction activities (as applicable); and s) Time for from scheduling of Commissioning Test to performance of Commissioning Test. OP 24 Proposal 12c is adopted, establishing a standard timeline for design and construction of interconnection-related distribution upgrades as follows: i) 60 business days for design and 60 business days for construction, or ii) design and construction timelines as agreed with the customer. The 60-day or agreed on timeline clock commences upon payment and after the customer has done everything necessary on their end to prepare for construction. OP 25 Proposal 12d is adopted with modifications, establishing a standard timeline for installation of Net Generation Output Meters as follows: i) 20 40 business days for design and 20 business days for construction, or ii) design and construction timelines as agreed with the customer. The 240- day clock commences on the date that both of the following have been satisfied: 1) the customer makes upon payment; and 2) and after the customer has received a permit from the Authority Having Jurisdiction

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and has done everything else necessary on their its end to prepare for construction. OP 40 Proposal 23c is adopted. Vehicle to Grid Electric Vehicle Supply Equipment with stationary inverter for direct current charging of vehicles (V2G DC EVSE) may be interconnected under the current Rule 21 language if the EVSE meets Rule 21 requirements, including applicable UL 1741 1547 SA and other updated smart inverter standards. OP 41 Proposal 23d is adopted. Vehicle to Grid Electric Vehicle Supply Equipment (EVSE) with stationary inverter for direct current charging of vehicles (V2G DC EVSE) with bidirectional capability may connect as one way managed or smart charging (V1G), load-only, and operate in unidirectional (charge only) mode upon certifying the EVSE with stationary inverter through applicable UL Power Control Systems CRD (UL CRD) and UL 1741 certification testing that i) the electric vehicle will not discharge if the EVSE is set to unidirectional charging mode; ii) the EVSE will not inadvertently change to bidirectional mode; and iii) factory default settings are set to unidirectional charging mode and cannot be changed without utility authorization. OP 45 Proposal 23i is adopted. Vehicle to Grid Alternating Current (V2G AC) system pilots are exempt, temporarily, from Rule 21 smart inverter requirements set forth in Section Hh, but remain subject to legacy inverter requirements located in Sections H and L (and related certification requirements) and all non-inverter related Rule 21 requirements. Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (Utilities) shall host a series of meetings with stakeholders to develop a temporary interconnection pathway for pilots seeking V2G AC interconnection that will ensure the necessary safety precautions. The first of these meetings shall begin no later than 30 days from the issuance of this decision. Following these meetings, Utilities shall propose a temporary pathway in the same Vehicle-to-Grid Workshop directed in Ordering Paragraph 43. Utilities shall request approval of the pathway in the Tier 3 Advice Letter submitted no later than 60 days following the workshop. For the purposes of this proposal, “pilot” shall mean those projects which have received funding from the California Energy Commission or approved Electric Program Investment Charge projects with interconnection requests dated no later than December 31, 2020. OP 42 Proposal 23e is adopted. Interconnection applicants with a Vehicle to Grid Electric Vehicle Supply Equipment with stationary inverter for direct current charging of vehicles (V2G DC EVSE) system may request permission to switch to bidirectional mode after completing the Rule 21 interconnection process and receiving permission to operate from a utility. Only the manufacturer or approved third-party installer may program or enable bidirectional operation after the permission to operate is given by a utility. For certification requirements, the applicable certification requirements based on EVSE year model may be evaluated for

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compliance with the requirements at the time of the interconnection request. OP 47 Proposal 27a is adopted. Utilities shall revise Rule 21 to: i) specifically allow smart inverter default settings to be changed; ii) account for IEEE 1547 and IEEE 1547.1 updated requirements; and iii) establish a process for requesting and approving non default inverter settings. Utilities shall include Rule 21 language changes necessary to implement Proposals 27a.i) and 27a.iii) as directed in Ordering Paragraph 56 below. Utilities shall file a Tier 2 Advice Letter implementing Proposal 27a.ii no later than nine months from the publication of IEEE 1547.1 OP 52 A modified Proposal A-B 3 is adopted but shall not be implemented until nine months after technical specifications and standards for Smart Inverter Phase III (Functions 3 and 8) have been approved by the standards approving bodies. Within 90 days of such approval, Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company shall submit a Tier 2 Advice Letter seeking to modify their Rule 21 tariffs to allow an inverter approved for non-export and limited export to be set using different maximum export value settings at different times of the year consistent with those required in OP 15 when meeting the qualifications for either Proposal A-B 1 or A-B 2. Within 60 days of the issuance of this decision, the Energy Division shall convene a series of stakeholder discussions focused on implementing Proposal A-B 3. Within six months of issuance of this decision the Utilities shall submit a Tier 3 Advice Letter outlining recommendations (as applicable) regarding the standard review, certification requirements, and interconnection processes necessary for implementation of the proposal.

OP 54 Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company shall hold a meeting of the Vehicle-to-Grid Alternating Current Subgroup (V2G AC Subgroup) with interested V2G AC industry stakeholders on a routine basis to provide the members stakeholders of the subgroup updates on the development status of the V2G AC interconnections standards update. The first meeting shall be held no later than six months from the issuance of this decision Commission guidance on the standard that should govern V2G AC systems and equipment certification procedures for V2G AC systems, and every six months thereafter until updated standards have been tested and approved. OP 55 Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company (Utilities) shall actively participate in the committees that update the applicable vehicle to grid alternating current interconnection standards as directed in OP 54. When standards have been approved, Utilities shall inform the Director of the Energy Division, who is authorized to reconvene the Vehicle to Grid

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Alternating Current Subgroup no later than 90 days from the issuance of approved updated standards.

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