MCE Board of Directors
April 20, 2023

MARCH FILINGS

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Oversee the
Resource Adequacy Program, Consider
Program Reforms and Refinements, and
Establish Forward Resource Adequacy
Procurement Obligations.

R.21-10-002
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS ON ASSIGNED COMMISSIONER’S AMENDED SCOPING MEMO AND RULING Evelyn Kahl,
General Counsel and Director of Policy
Eric Little,
Director Of Regulatory Affairs
Lauren Carr,
Senior Market Policy Analyst

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
One Concord Center
2300 Clayton Road, Suite 1150
Concord, CA 94520
Telephone: (510) 980-9459
E-mail: [email protected]
March 3, 2023
FILED
03/03/23
04:59 PM
R2110002
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 II. THE COMMISSION SHOULD IGNORE THE IOUS’ BASELESS
SUPPORT FOR LIMITING LSE EXPANSION ................................................................2 III. THE COMMISSION SHOULD NOT ALLOCATE COSTS OF EFFECTIVE PRM PROCUREMENT FIRST TO DEFICIENT LSES ....................................................3 IV. THE COMMISSION SHOULD REJECT PG&E’S AND SCE’S
OBJECTIONS TO THE CPE TRANSPARENCY PROPOSALS ......................................3 V. SCE’S OBJECTION TO CALCCA’S CPE TIMELINE PROPOSAL

MISREPRESENTS CPE PROCUREMENT PRACTICES ALLOWED IN
D.22-03-034 .........................................................................................................................5 VI. SCE IGNORES RISKS TO SELF-SHOWING THAT LIKELY OUTWEIGH THE BENEFITS ..................................................................................................................6 VII. THE COMMISSION SHOULD NOT REQUIRE LSES TO BE THEIR OWN SCS FOR RA IMPORTS AND SHOULD ADOPT AREM’S PROPOSAL TO

HAVE LSES DECLARE WHO THE SC IS FOR THE TRANSACTION TO
HELP ENERGY DIVISION STAFF VERIFY TRANSACTIONS ....................................7 VIII. PG&E’S “CAUTION” ON CALCCA’S RA IMPORTS BIDDING

PROPOSAL IGNORES THE STATE OF CAPACITY CONDITIONS
WEST-WIDE AND THE INEFFICIENCIES CREATED BY A MUST-FLOW REQUIREMENT.....................................................................................................8 IX. LOCAL AREA RELIABILITY SOLUTIONS REQUIRE

COMPREHENSIVE REVIEW AMONG THE RA AND IRP
PROCEEDINGS AND THE TRANSMISSION PLANNING PROCESS .........................9 X. CONCLUSION ..................................................................................................................10 ii

SUMMARY OF RECOMMENDATIONS
• The California Public Utilities Commission (Commission) should ignore the investor-owned utilities’ (IOU) baseless support for limiting load-serving entity (LSE) expansion; • The Commission should not allocate costs of effective Planning Reserve Margin (PRM) procurement first to deficient LSEs;
• The Commission should reject Pacific Gas and Electric Company’s (PG&E) and Southern California Edison Company’s (SCE) objections to the central procurement entity (CPE) transparency proposals;
• SCE’s objection to California Community Choice Association’s (CalCCA) CPE timeline proposal misrepresents CPE procurement practices allowed in Decision 22-03-034; • SCE ignores risks to self-showing that likely outweigh the benefits; • The Commission should not require LSEs to be their own scheduling coordinators (SC) for Resource Adequacy (RA) imports and should adopt Alliance for Retail Energy Markets’ (AReM) proposal to have LSEs declare who the SC is for the transaction to help Energy Division staff verify transactions;
• PG&E’s “caution” on CalCCA’s RA imports bidding proposal ignores the state of capacity conditions west-wide and the inefficiencies created by a must-flow requirement; and • Local area reliability solutions require comprehensive review between the RA and Integrated Resource Plan (IRP) proceeding and the Transmission Planning Process (TPP).

CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS ON ASSIGNED COMMISSIONER’S AMENDED SCOPING MEMO AND RULING I. INTRODUCTION
California Community Choice Association (CalCCA) submits these Reply Comments in response to the Assigned Commissioner’s Amended Scoping Memo and Ruling1 (Ruling), dated September 2, 2022, on the workshop and all proposals filed. These Reply Comments are timely filed based on the E-mail Ruling Granting Western Power Trading Forum's Request for Extension to File Comments on Phase 3 Proposals,
2 dated February 13, 2023. These Reply Comments
respond to select party Opening Comments3 filed on February 24, 2023 related to requirements for LSE expansions, the planning reserve margin (PRM), the central procurement entity (CPE) structure, resource adequacy (RA) import bidding rules, and the local RA process. In summary:
• The California Public Utilities Commission (Commission) should ignore the investor-owned utilities’ (IOU) baseless support for limiting load-serving entity (LSE) expansion; • The Commission should not allocate costs of effective PRM procurement first to deficient LSEs;
• The Commission should reject Pacific Gas and Electric Company’s (PG&E’s) and Southern California Edison Company’s (SCE) objections to the CPE transparency proposals;
• SCE’s objection to CalCCA’s CPE timeline proposal misrepresents CPE procurement practices allowed in Decision (D.) 22-03-034;4
• SCE ignores risks to self-showing that likely outweigh the benefits; 1 Assigned Commissioner’s Amended Scoping Memo and Ruling, R.21-10-002 (Sept. 2, 2022) (Ruling): https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M496/K684/496684932.PDF. 2 E-mail Ruling Granting Western Power Trading Forum's Request for Extension to File Comments on Phase 3 Proposals, R.21-10-002 (Feb. 13, 2023):
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M502/K200/502200464.PDF. 3 All references herein to party Opening Comments are to the February 24, 2023 Comments filed in this Rulemaking (R.) 21-10-002.
4 D.22-03-034, Decision on Phase 1 of the Implementation Track: Modifications to the Central Procurement Entity Structure, R.21-10-002 (Mar. 17, 2022):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M460/K580/460580209.PDF. 2 • The Commission should not require LSEs to be their own scheduling coordinators (SC) for RA imports and should adopt Alliance for Retail Energy Markets’ (AReM) proposal to have LSEs declare who the SC is for the transaction to help Energy Division staff verify transactions;
• PG&E’s “caution” on CalCCA’s RA imports bidding proposal ignores the state of capacity conditions west-wide and the inefficiencies created by a must-flow requirement; and • Local area reliability solutions require comprehensive review among the RA and integrated resource planning (IRP) proceedings and the Transmission Planning Process (TPP).

II. THE COMMISSION SHOULD IGNORE THE IOUS’ BASELESS SUPPORT

FOR LIMITING LSE EXPANSION
Energy Division staff proposes that a community choice aggregator (CCA) or electric service provider (ESP) must have not had any RA deficiencies greater than 2.5 percent of its system RA month ahead filings during the previous two calendar years for that CCA or ESP to expand and take on any new customer load.5 CalCCA strongly opposes this proposal and provided extensive arguments in its Opening Comments explaining why the proposal (1) violates the Commission’s legal authority, and (2) does not result in increased reliability.6 The three IOUs support this proposal but provide no explanation as to why the proposal falls within the Commission’s legal authority or how the proposal would increase reliability. The Commission should ignore the IOUs’ unsubstantiated support for Energy Division’s proposal to limit LSE expansions based on RA compliance and reject the proposal on the legal and policy grounds explained in CalCCA’s opening comments.
5 Administrative Law Judge’s Ruling on Energy Division’s Phase 3 Proposals Appendix A: Energy Division Proposals for Proceeding R.21-10-002 (Jan. 20, 2023) (Energy Division Proposal), at 34:
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M501/K407/501407493.PDF. 6 CalCCA Opening Comments at 19-27.
3 III. THE COMMISSION SHOULD NOT ALLOCATE COSTS OF EFFECTIVE

PRM PROCUREMENT FIRST TO DEFICIENT LSES
In its proposal, Energy Division asks parties to comment on whether the Commission should allocate costs associated with effective PRM procurement first to LSEs with RA deficiencies.7
The Commission should not allocate effective PRM procurement costs first to deficient LSEs. As PG&E notes:
“…having deficient LSEs pay a larger share of the emergency procurement costs does not follow cost-causation principles. Since emergency procurement is to increase the level of reliability for all customers above that reflected in the PRM, deficient LSEs should only be responsible for any increase in emergency procurement caused by their deficiency, and not a greater share of the entire emergency procurement itself.”8
As described in CalCCA’s opening comments, the effective PRM should be met exclusively by non-RA resources.9 Because a deficient LSE would not have been able to procure resources used to meet the effective PRM to resolve its own individual deficiency, it does not make sense for a deficient LSE to take on additional costs associated with effective PRM procurement. If the effective PRM were to be met with RA resources, the Commission should not allocate costs to deficient LSEs because doing so could create perverse incentives to further cannibalize the RA stack for effective PRM procurement.

IV. THE COMMISSION SHOULD REJECT PG&E’S AND SCE’S OBJECTIONS TO

THE CPE TRANSPARENCY PROPOSALS
CalCCA proposes that in addition to the reporting requirements adopted in D.22-03-034, the Commission also requires CPEs to report publicly:
• If any offers or self-showings were not selected by the CPE, why were they not selected (price, inability to negotiate contract terms, other); and 7 Energy Division Proposal at 8.
8 PG&E Opening Comments at 3.
9 CalCCA Opening Comments at 29-31.
4 • Total Net Qualifying Capacity (NQC) of local RA not offered or self-shown.10 PG&E opposes the first item, stating that CalCCA’s proposal would require a non-aggregated breakdown that may expose confidential market-sensitive information.11 CalCCA clarifies that its proposal is not for the CPE to provide non-aggregated information but rather for the CPE to provide aggregated megawatts (MW) that were not selected by the CPE by reason they were not selected (including price, inability to negotiate contract terms, or other reasons).

This is consistent with Energy Division’s transparency proposal, which PG&E supports.12 SCE opposes various elements of CalCCA’s and Energy Division’s CPE transparency proposals. SCE states that it does not have the information necessary to determine which resources were not offered or self-shown to the CPE. This is untrue. The NQC list posts all RA-eligible resources online and under development by local area.13 The CPE can use the NQC list and information on which resources did participate in its solicitations or self-showing process to easily determine which local resources were not offered or self-shown. While it is true that the CPE would not have any additional information on whether those resources not offered or self-shown were sold to other LSEs or market participants, the volume of resources not offered or self-shown would still provide valuable information to market participants about the state of local RA capacity.

Additionally, while SCE agrees to provide Energy Division with the resources that bid into its CPE solicitation and the reason they were not selected (including unreasonably high pricing, interconnection viability, or other reasons), SCE opposes providing such information to market 10 California Community Choice Association’s Proposals in Response to Assigned Commissioner’s Amended Scoping Memo and Ruling, R.21-10-002 (Jan. 20, 2023) (CalCCA Proposals), at 11:
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M501/K418/501418731.PDF. 11 PG&E Opening Comments at 8. 12 PG&E Opening Comments at 5.
13 The CAISO NQC List is updated regularly and posted here:
http://www.caiso.com/planning/Pages/ReliabilityRequirements/Default.aspx. 5 participants. SCE claims that the information would not help LSEs better manage their procurement and that the information is market sensitive. CalCCA disagrees. First, this information would be useful to market participants, including LSEs who complete their system RA procurement after CPEs conduct their local RA procurement. Additionally, it would help stakeholders better understand how the CPE framework is functioning, including the sources of any CPE deficiencies. This information would not be market sensitive because CPEs would report it at an aggregated level in MW by reason the CPE did not select those MW. CPEs would not publicize any price information, just aggregated MW. The Commission should, therefore, require public reporting of aggregated MW not selected by reason they were not selected.

V. SCE’S OBJECTION TO CALCCA’S CPE TIMELINE PROPOSAL

MISREPRESENTS CPE PROCUREMENT PRACTICES ALLOWED IN
D.22-03-034
CalCCA proposes that CPEs complete their procurement after year two, the first year the CPE has a 100 percent obligation.14 This proposal would avoid the uncertainty experienced when CPE procurement did not complete until August 2022 for RA year 2023. In its comments, SCE suggests this proposal is unnecessary because the Commission already requires CPEs to procure 100 percent of their year two local RA obligation. While it is true that CPEs have a 100 percent obligation in year two, the timeline adopted in D.22-03-034 allows CPEs to essentially forego that obligation and procure until the August prior to the compliance year. This creates unworkable amounts of uncertainty for LSEs needing to do their own system and flexible RA procurement.

SCE also objects to CalCCA’s recommendation that the Commission direct CPEs to stop procurement for 2024 upon issuance of a Decision in June 2023.15 SCE’s objection fails to recognize that, as CalCCA’s proposal states, this would only apply for procurement done for 2024 14 CalCCA Proposals at 8-10.
15 SCE Opening Comments at 15.
6 because the timing of the decision comes out too late to implement CalCCA’s proposed timeline change for compliance year 2024. CalCCA proposed this solution as a transitionary mechanism because if the CPEs did not complete 100 percent of their year two obligation for RA year 2024, then the CPEs would still be procuring for 2024 by the time the Decision comes out.

For all years after 2024, CPE procurement should end after the year two obligation (including 2025 and 2026, in which the CPE has a 100 percent and 50 percent obligation this year).

If the SCE CPE procures 100 percent of its year 2 obligation as it suggests is the requirement, then its procurement for 2024 would already be complete and this proposal would not affect its procurement. If, however, the CPE was short in its 2022 procurement to meet its 100 percent obligation for 2024, then it is unreasonable to continue to allow the CPE to perform procurement through August as was done in 2022. CPE procurement for 2024 should therefore stop as CalCCA proposed in June of 2023. The CPE should have already been attempting to meet its short position at the end of its 2022 RFO cycle to meet any unmet needs for 2024. If the CPE has not done so, that should not place the burden on LSEs by allowing the CPE to continue to procure through August. This places the LSEs under significant uncertainty with regard to CPE-allocated procurement that meets the LSEs’ obligations.

VI. SCE IGNORES RISKS TO SELF-SHOWING THAT LIKELY OUTWEIGH

THE BENEFITS
As CalCCA describes in its opening comments, an LSE faces significant risks to self-showing its resources to the CPE because if it self-shows, the LSE must, in each month-ahead RA showing, include the self-shown resource for those months it was shown in the year-ahead showing.16 This limits the LSE’s flexibility to manage its portfolio, because it cannot sell the resource for months it is long or use the resource for substitution if another resource in its portfolio 16 CalCCA Proposals at 12-13.
7 goes on outage. SCE suggests, “…CalCCA ignores the fact that LSEs use 100 percent of their self-shown resource towards their own system requirements and self-showing local resources reduces the need of the CPE to procure additional local RA from third parties thereby reducing costs that are passed on to all LSEs, including the self-showing LSE.”17 CalCCA did not ignore this fact.

However, that fact is offset by a constraint self-showing places on an LSEs portfolio that can be avoided by retaining the resource, not self-showing it, and using 100 percent of the LSEs procured resource towards its own obligations without any of the added risks associated with self-showing.

This is likely a better use of the resource for the LSE in many cases, particularly when system RA is scarce. The Commission should therefore adopt CalCCA’s proposal to remove some of the risks of self-showing by allowing LSEs that are either not receiving the local capacity requirement reduction compensation mechanism (LCR-RCM) or who choose to forfeit the LCR-RCM to self-show without the current restrictions placed upon the self-showing LSE which require the self-showing LSE to show the resource in all months it was shown in the year-ahead.

VII. THE COMMISSION SHOULD NOT REQUIRE LSES TO BE THEIR OWN SCS FOR RA IMPORTS AND SHOULD ADOPT AREM’S PROPOSAL TO HAVE

LSES DECLARE WHO THE SC IS FOR THE TRANSACTION TO HELP

ENERGY DIVISION STAFF VERIFY TRANSACTIONS
Energy Division proposes that the Commission require LSEs to be the SC for their non-resource-specific RA contracts. With this proposal, Energy Division aims to ensure LSEs meet Commission requirements associated with RA imports.
18 A number of parties recommend the
Commission reject this proposal because many LSEs do not perform their own SC functions and requiring them to take on this role could be overly burdensome and costly.19 CalCCA agrees with 17 SCE Opening Comments at 15.
18 Energy Division Proposals at 37.
19 AReM Opening Comments at 13, Bonneville Power Administration Opening Comments at 3, California Independent System Operator Corporation (CAISO) Department of Market Monitoring 8 these parties. The additional costs and administrative burdens this requirement creates could effectively prohibit LSEs from using RA imports to meet their RA obligations. CalCCA also agrees with parties that the Commission could adopt more efficient solutions to reach Energy Division’s aims of tracking RA imports to ensure LSEs follow Commission requirements. AReM proposed one such solution: that the Commission require LSEs to identify who their SC is in their RA showings to allow staff to verify import RA transactions.20 CalCCA supports this proposal with one clarification, which is for the LSE to identify the SC associated with their import RA transaction in their RA showings, as the LSE’s SC scheduling its load may be different from the SC scheduling the import.

VIII. PG&E’S “CAUTION” ON CALCCA’S RA IMPORTS BIDDING PROPOSAL

IGNORES THE STATE OF CAPACITY CONDITIONS WEST-WIDE AND THE

INEFFICIENCIES CREATED BY A MUST-FLOW REQUIREMENT
CalCCA proposes to revise the RA import bidding rules to attract additional imports RA offers to Commission-jurisdictional LSEs. CalCCA’s proposal would allow RA imports to bid up to a bid cap set based on estimated fuel, GHG, and variable operations and maintenance costs. 21 PG&E cautions that this proposal may not increase the overall volume of imports because imports can receive capacity and energy payments to make them whole.22 While it is true that imports can recover their costs through both capacity and energy payments, PG&E’s comments fail to recognize that the entire West is experiencing capacity constraints and suppliers have many prospective buyers they can choose to contract with. Under these conditions, the existing bidding (DMM) Opening Comments at 5-6, PG&E Opening Comments at 10-11, Vistra Corp. (Vistra) Opening Comments at 26.
20 AReM Opening Comments at 13.
21 CalCCA Proposals at 22-25.
22 PG&E Opening Comments at 11.
9 requirements on RA imports may result in suppliers contracting with non-jurisdictional entities that do not have such onerous requirements.

Additionally, requiring RA imports to flow during the availability assessment hours creates market inefficiencies that the Commission should avoid. Requiring energy to flow during the availability assessment hours means the CAISO will dispatch the resource whether it needs it or not, and regardless of whether or not less expensive resources are available to serve the same need.

This essentially puts a mandatory hedge on LSEs, where the value of the hedge is unknown and the cost of such an arrangement is incorporated into RA contracts.

As the CAISO DMM explains:
“…an appropriately low import RA bid cap could provide many of the same reliability benefits as the current $0/MWh bid requirement or self-schedule requirement. Meanwhile, increasing the import RA bid cap above $0/MWh as suggested by CalCCA could provide the benefit of increasing the overall efficiency of CAISO market schedules… This increased efficiency could presumably be passed along to load serving entities through lower resource adequacy contract costs.”23
CalCCA’s proposal sets the RA import bid caps at levels that do not allow suppliers that bid in a manner that nearly guarantees they will not be dispatched but also ensures they cover their costs under most conditions. This change will ensure RA imports are incented to provide RA to Commission-jurisdictional LSEs over non-jurisdictional LSEs and improve market efficiencies.

IX. LOCAL AREA RELIABILITY SOLUTIONS REQUIRE COMPREHENSIVE

REVIEW AMONG THE RA AND IRP PROCEEDINGS AND THE

TRANSMISSION PLANNING PROCESS
Currently, if insufficient generation exists in a local area to meet the local RA requirement, the Commission will set the local RA requirement at the total NQC of the existing generation in the local area. Vistra proposes to modify this practice such that if insufficient generation exists in local 23 CAISO DMM Opening Comments at 9.
10 areas to meet the year two and year three requirements, the Commission require CPEs to procure new generation in the local areas to cover the insufficiency.24 The CAISO opposes this proposal, given it does not consider the interaction between generation and transmission in local areas.25 CalCCA agrees with the CAISO that the Commission should reject this proposal. As the CAISO correctly points out, local deficiencies are often resolved through transmission solutions, rather than new generation. Furthermore, the Commission and CAISO must work together to form a coordinated approach to RA, IRP, LCR, and the TPP that evaluates the most cost-effective local area reliability solutions that can reduce reliance on GHG emitting resources.26 The Commission should reject Vistra’s proposal as it fails to recognize that new generation in local areas is not always the best solution to resolve local reliability needs.

X. CONCLUSION
For all the foregoing reasons, CalCCA respectfully requests consideration of its Reply Comments herein and looks forward to an ongoing dialogue with the Commission and stakeholders.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 3, 2023
24 Implementation Track Phase 3 Proposals of Vistra Corp., R.21-10-002 (Jan. 20, 2023), at 6-9. 25 CAISO Opening Comments at 12.
26 CalCCA has explained the need for coordinated planning for local reliability needs in the IRP proceeding here: California Community Choice Association’s Comments on Administrative Law Judge’s Ruling Seeking Comments on Staff Paper on Procurement Program, R.20-05-003 (Dec. 12, 2022), at 46- 48: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M499/K887/499887293.PDF.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Implementing Senate Bill 846 Concerning
Potential Extension of Diablo Canyon Power
Plant Operations.

R.23-01-007
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY

COMMENTS ON ORDER INSTITUTING RULEMAKING TO

CONSIDER POTENTIAL EXTENSION OF DIABLO CANYON POWER
PLANT OPERATIONS IN ACCORDANCE WITH SENATE BILL 846
Evelyn Kahl
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
One Concord Center
2300 Clayton Road, Suite 1150
Concord, CA 94520
Telephone: (510) 980-9459
Email: [email protected]
Tim Lindl
Nikhil Vijaykar

KEYES & FOX LLP
580 California Street, 12th Floor
San Francisco, CA 94104
Telephone: (408) 621-3256
Email: [email protected]
[email protected]
On behalf of
California Community Choice Association
March 7, 2023
FILED
03/07/23
03:12 PM
R2301007
i

TABLE OF CONTENTS
SUMMARY OF RECOMMENDATIONS ........................................................................ ii I. INTRODUCTION ...............................................................................................................2 II. THE COMMISSION MUST ADDRESS THE ALLOCATION OF

BENEFITS FROM EXTENDED OPERATIONS AT DCPP IN THIS
RULEMAKING ...................................................................................................................2 III. CONCLUSION ....................................................................................................................3 ii

SUMMARY OF RECOMMENDATIONS
• The California Public Utilities Commission (Commission) should not authorize any mechanism for the recovery of Diablo Canyon Power Plant (DCPP) extended operations costs without concurrently addressing the allocation of associated benefits. • Whether the Commission addresses the annual process for the review and approval of DCPP extended operations costs in Phase 1 or Phase 2 of this rulemaking, the Commission must establish that process by early 2024.
• The Commission should set a date for an evidentiary hearing at this time to not preclude the opportunity for record development through witness examination. • The Commission should adopt California Community Choice Association’s alternative scheduling proposal, which allows for resolution of Phase 1 by the end of 2023.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Implementing Senate Bill 846 Concerning
Potential Extension of Diablo Canyon Power
Plant Operations.

R.23-01-007
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY

COMMENTS ON ORDER INSTITUTING RULEMAKING TO

CONSIDER POTENTIAL EXTENSION OF DIABLO CANYON POWER
PLANT OPERATIONS IN ACCORDANCE WITH SENATE BILL 846
The California Community Choice Association1 (CalCCA) submits these reply comments in response to the Order Instituting Rulemaking to Consider Potential Extension of Diablo Canyon Power Plant Operations In Accordance With Senate Bill 846, 2 issued January
20, 2023, pursuant to Rule 6.2 of the California Public Utilities Commission’s (Commission) Rules of Practice and Procedure,
3 and the directives provided by the OIR.
1 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Desert Community Energy, East Bay Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Choice Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 2 Order Instituting Rulemaking to Consider Potential Extension of Diablo Canyon Power Plant Operations in Accordance With Senate Bill 846, R.23-01-007 (Jan. 20, 2023) (OIR):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M501/K368/501368884.PDF. 3 State of California Public Utilities Commission Rules of Practice and Procedure (May 1, 2021), at 45: https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/rules-of-practice-and-procedure-may-2021.pdf. 2 I. INTRODUCTION
These comments respond to the Green Power Institute’s (GPI)4 recommendation
regarding the scope of this rulemaking. GPI recommends that the Commission assess the reliability need for Diablo Canyon Power Plant (DCPP) in other ongoing rulemakings like the Resource Adequacy (RA) or Integrated Resource Planning (IRP) rulemakings, and not in this rulemaking. Even if the Commission agrees with GPI, it should nevertheless address the allocation of benefits associated with extended operations of DCPP in this rulemaking, for the reasons described in CalCCA’s opening comments and in these reply comments.

II. THE COMMISSION MUST ADDRESS THE ALLOCATION OF BENEFITS

FROM EXTENDED OPERATIONS AT DCPP IN THIS RULEMAKING
In opening comments, GPI recommends that the Commission assess the reliability need for DCPP in an ongoing rulemaking such as the RA rulemaking or the IRP rulemaking, and not in this rulemaking. With respect to RA, DCPP’s current contributions to reliability are well-accepted, as the facility currently has a qualifying capacity value and deliverability assessment that demonstrates it can reliably serve load within the CAISO-controlled grid. This reliability impact should not be in question within this rulemaking (R.23-01-007) nor is it presently in question in the RA rulemaking itself where DCPP has provided RA capacity from the inception of the RA program. CalCCA does not object to the Commission assessing DCPP’s reliability contributions within the RA and/or IRP rulemakings. However, the Commission must address the allocation of the benefits of continued operations at DCPP (such as RA capacity) in this rulemaking (specifically, in Phase 1), where it is considering the recovery of extended operations costs. As CalCCA explained in its initial comments, costs and benefits are two sides of the same 44 Comments of the Green Power Institute on the Order Instituting Rulemaking to Extend Operations at Diablo Canyon Power Plant, R.23-01-007 (Feb. 21, 2023):
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M502/K376/502376645.PDF. 3 coin, and failing to address the benefits of extended operations in this rulemaking would risk leaving non-PG&E customers without adequate or fair opportunities to realize the value that they are paying for.

III. CONCLUSION
For all the foregoing reasons, CalCCA requests that the Assigned Commissioner and Administrative Law Judge modify the scoping issues and procedural schedule consistent with CalCCA’s recommendations in these and its opening comments.

Respectfully submitted,
Evelyn Kahl
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 7, 2023

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Consider New
Approaches to Disconnections and
Reconnections to Improve Energy Access and
Contain Costs.

R.18-07-005
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING DIRECTING UTILITIES TO PROVIDE

DATA AND REQUESTING COMMENTS ON PILOT QUESTIONS
Evelyn Kahl,
General Counsel and Director of Policy
Leanne Bober,
Senior Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
One Concord Center
2300 Clayton Road, Suite 1150
Concord, CA 94520
Telephone: (510) 980-9459
E-mail: [email protected]
March 13, 2023
FILED
03/13/23
04:59 PM
R1807005
ii

TABLE OF CONTENTS
I. THE COMMISSION SHOULD ADOPT RECOMMENDATIONS BY
CFORAT AND NCLC TO EVALUATE AMP AND LTPP “SUCCESS”
THROUGH ONGOING ADDITIONAL IOU DATA ........................................................2 II. THE IOUS SHOULD BE REQUIRED TO PROVIDE DATA REGARDING CUSTOMERS ELIGIBLE FOR AMP ................................................................................2 III. CONCLUSION ....................................................................................................................3

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Consider New
Approaches to Disconnections and
Reconnections to Improve Energy Access and
Contain Costs.

R.18-07-005
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S REPLY COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING DIRECTING UTILITIES TO PROVIDE

DATA AND REQUESTING COMMENTS ON PILOT QUESTIONS
California Community Choice Association1 (CalCCA) submits these reply comments in response to the Administrative Law Judge’s Ruling Directing Utilities to Provide Data and Requesting Comments on Pilot Questions2 (Ruling), dated February 13, 2023. CalCCA supports the recommendations of the Center for Accessible Technology (CforAT) and the National Consumer Law Center (NCLC) to require ongoing, accurate reporting of data to track success of the Arrearage Management Plan and the long term payment plans (LTPPs). CalCCA also requests that the Commission require the investor-owned utilities (IOUs) to provide additional information regarding customers eligible for Arrearage Management Plan (AMP) enrollment (in addition to the number of AMP enrolled customers).
1 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Desert Community Energy, East Bay Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Choice Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 2 Administrative Law Judge’s Ruling Directing Utilities to Provide Data and Requesting Comments on Pilot Questions, Rulemaking (R.) 18-07-005 (Feb. 13, 2023):
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M502/K200/502200451.PDF. 2 I. THE COMMISSION SHOULD ADOPT RECOMMENDATIONS BY CFORAT AND NCLC TO EVALUATE AMP AND LTPP “SUCCESS” THROUGH

ONGOING ADDITIONAL IOU DATA
While the data provided by the IOUs in response to the Ruling give an overall snapshot of the AMP at a point in time (December 31, 2022), evaluation of success will require comparisons of data over time. As noted by CforAT and NCLC,3 requiring the IOUs to submit ongoing, accurate, comparative data will allow the Commission and stakeholders to evaluate the performance of AMP and LTPPs, as well as whether modifications to the programs are necessary.4 II. THE IOUS SHOULD BE REQUIRED TO PROVIDE DATA REGARDING

CUSTOMERS ELIGIBLE FOR AMP
In addition to providing information regarding customers enrolled in AMP at a particular time, the IOUs should also be required to provide the “total customers eligible for AMP” to assess the quality and success of IOU enrollment efforts. The second step is then to address how well IOUs performed in assisting enrolled customers to complete the AMP program. For example, the AMP data provided by the IOUs as of December 31, 2022 (in response to the Ruling) demonstrates that Pacific Gas and Electric Company (PG&E) has enrolled 215,079 customers in AMP over time,5 while Southern California Edison Company (SCE) has enrolled 78,010 3 CforAT/NCLC Opening Comments at 9.
4 CalCCA has previously recommended several modifications to AMP and LTPPs which can be implemented now to encourage successful completion of the programs, including: (1) ordering the conclusion of automatic enrollment in LTPPs, and instead determining in this proceeding the most effective customer engagement to tailor payment plans to individual customer needs; and (2) modifying the AMP to better serve struggling customers by (a) allowing payments of 50 percent or more of the monthly amount due to qualify as an “on time payment” for two months out of the 12-month period, (b) providing the option of a “sliding scale” in which payment amounts ramp up over the 12-month period to encourage customers to gradually increase their monthly obligations, (c) reducing the “waiting period” for re-enrollment in AMP from 12 to six months, and (d) allowing customers removed from AMP for system/automation issues that are not the fault of the customer to be immediately re-enrolled. See R.18-07-005, California Community Choice Association’s Comments on Assigned Commissioner’s Phase 2 Scoping Memo and Ruling (Aug. 5, 2022), at 4-7; California Community Choice Association’s Comments on Administrative Law Judge’s Ruling Relating to the Phase 2 Workshop in October 2022 (Dec. 9, 2022), at 3-7. 5 PG&E Opening Comments at 1.
3 customers over time.6 Given PG&E’s total residential customers (4,947,963 in 2021 (37 percent of California residential customer share)) versus SCE’s total residential customers (4,503,286 in 2021 (34 percent of California residential customer share)),7 a further inquiry into total customers eligible for AMP may explain SCE’s proportionally significantly lower AMP enrolled customers.

In addition, while PG&E has more customers enrolled which by itself appears successful, a ratio of enrolled versus eligible will provide insight into AMP enrollment overall.

III. CONCLUSION
For all the foregoing reasons, CalCCA respectfully requests consideration of these Reply Comments and looks forward to an ongoing dialogue with the Commission and stakeholders.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 13, 2023
6 SCE Opening Comments at 1.
7 U.S. Energy Information Administration, Form 861 (2021).

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Review,
Revise, and Consider Alternatives to the
Power Charge Indifference Adjustment.

R.17-06-026
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS ON
ADMINISTRATIVE LAW JUDGE’S RULING REQUESTING COMMENTS ON

SUPPLEMENTAL GREENHOUSE GAS-FREE PROPOSAL AND ISSUES IN SCOPE Evelyn Kahl,
General Counsel and Director of Policy
Leanne Bober,
Senior Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
One Concord Center
2300 Clayton Road, Suite 1150
Concord, CA 94520
Telephone: (510) 980-9459
E-mail: [email protected]
March 17, 2023
FILED
03/17/23
04:05 PM
R1706026
i

TABLE OF CONTENTS
I. INTRODUCTION ...............................................................................................................1 A. Energy Division Staff GHG-Free Supplemental Proposal ......................................2 B. Additional Issues in Scope .......................................................................................4 II. THE SUPPLEMENTAL PROPOSAL SHOULD BE ADOPTED WITH
MODIFICATIONS ..............................................................................................................5 A. The Frequency of an IOU’s Election of an Allocation or MPB Should be Limited to Allow Adequate Time for LSE Long Term Procurement and Compliance Planning ........................................................................................5 B. Statutory Requirements and the Prohibition Against Cost Shifting Require the Commission to Allow Unbundled Customers to Elect to Receive GHG-Free Value for Non-Hydro, Nuclear Resources ...............................6 III. THE COMMISSION SHOULD ADD TO THE PCIA PROCEEDING

SCOPE ISSUES REGARDING RE-VINTAGING IOU POWER

PURCHASE AGREEMENTS (PPA) AND CREDITING OF BANKED
RECS....................................................................................................................................8 A. The Commission Should Grant CalCCA’s Outstanding September Motion in this Proceeding Regarding Re-vintaging IOU PPAs ..............................8 B. An Urgent Need Exists for a Permanent Framework to Credit the PABA When Utilities Use Banked RECs for RPS Compliance............................11 IV. CONCLUSION ..................................................................................................................15 ii

SUMMARY OF RECOMMENDATIONS
• California Community Choice Association (CalCCA) supports the California Public Utilities Commission (Commission) Energy Division Staff’s Supplemental GHG-Free Proposal (Supplemental Proposal), with the following recommended modifications:
o The frequency of an investor-owned utility’s (IOU’s) election of an allocation or Market Price Benchmark (MPB) should be limited to either a one-time or multi-year option to allow load-serving entities (LSEs) adequate time for long-term procurement and compliance planning; and
o To comply with the requirements of Public Utilities Code sections 366.2(g) and 365.2 allowing unbundled customers to elect to receive the benefits of the resources they fund through the PCIA and to prevent cost-shifting, the Commission should order the continuance of the separate interim allocations of non-hydropower (hydro), including nuclear, GHG-Free attributes, while monitoring the market for GHG-free non-hydro transactions. If a market for such GHG-Free non-hydro transactions emerges, the Commission should then establish a non-hydro MPB, and adopt the Supplemental Proposal’s methodology for IOU elections of allocations or MPBs for hydro and non-hydro GHG-Free value.
• The Commission should address the following issues prior to closing this proceeding:
o The appropriate venue for determining vintaging changes when an IOU procurement contract is amended, renewed, or extended, which is the subject of a currently outstanding Motion to Amend Assigned Commissioner’s Second Amended Scoping Memo and Ruling, filed by CalCCA in this proceeding on September 9, 2022; and
o The urgent need for a permanent framework to credit the Portfolio Allocation Balancing Account when utilities use banked renewable electricity credits for Renewable Portfolio Standards compliance, which the Commission has noted in two decisions, Decision (D.) 20-02-047 and D.22-12-012, should be developed within this proceeding.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Review,
Revise, and Consider Alternatives to the
Power Charge Indifference Adjustment.

R.17-06-026
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S COMMENTS ON
ADMINISTRATIVE LAW JUDGE’S RULING REQUESTING COMMENTS ON

SUPPLEMENTAL GREENHOUSE GAS-FREE PROPOSAL AND ISSUES IN SCOPE California Community Choice Association1 (CalCCA) submits these comments in response to the Administrative Law Judge’s Ruling Requesting Comments on Supplemental Greenhouse Gas-Free Proposal and Issues in Scope2 (Ruling), dated March 3, 2023.

I. INTRODUCTION
CalCCA’s comments address the following Ruling issues: (1) Energy Division’s Supplemental Greenhouse Gas Free (GHG-Free) Proposal (Supplemental Proposal);3 and (2) recommendations for additional issues to be added to the scope of this proceeding. 1 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Desert Community Energy, East Bay Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Choice Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 2 Administrative Law Judge’s Ruling Requesting Comments On Supplemental Greenhouse Gas-Free Proposal and Issues In Scope, R.17-06-026 (Mar. 3, 2023):
https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M502/K987/502987675.PDF. 3 The Supplemental Proposal is Attachment A to the Ruling. 2 A. Energy Division Staff GHG-Free Supplemental Proposal CalCCA appreciates Energy Division Staff’s efforts to quantify the recognized GHG-Free value in the investor-owned utility (IOU) power charge indifference adjustment (PCIA) portfolios.

As a result of the information obtained from its summer 2022 data request, Energy Division Staff finds “a premium for GHG-Free resources” and that “GHG-Free resources are undervalued in the PCIA.”4 With GHG-Free value established, the only remaining issue is how to ensure both bundled and unbundled customers, including customers of community choice aggregators (CCAs), share the value of such resources in proportion to their responsibility for PCIA costs, as required by Public Utilities Code sections 366.2(g) and 365.2. Specifically, section 366.2(g) requires the value to be recovered by CCA customers in one of two ways: (1) reducing the costs paid by CCA customers by the incremental value of benefits that remain with bundled service customers (i.e., a Market Price Benchmark (MPB)); or (2) an allocation of a fair and equitable share of those benefits (i.e., an allocation of resources). Section 365.2 also prohibits inequitable cost shifting between bundled and unbundled customers, thereby requiring the proportional distribution of the value/benefits.

The initial September 12 Staff proposal recommended a GHG-Free MPB (instead of an allocation).
5 Calculation of the MPB would include transactions for in-California Independent System Operator Corporation (CAISO) and out-of-CAISO large hydropower and nuclear resources (as well as combined resources to the extent the percentage of GHG-Free, non-Renewable Portfolio Standard (RPS) eligible resources can be identified).6 4 Administrative Law Judge’s Ruling Requesting Comments on GHG-Free Resources Staff Proposal and Other Issues, R.17-06-026 (Sept. 12, 2022), Attachment A, “GHG Free Data Analysis and Staff Proposal” (September 12 Staff Proposal), at 5-6.
5 September 12 Staff Proposal, at 6-7.
6 Id. at 7.
3 The Supplemental Proposal changes this methodology, allowing IOUs to choose either GHG-Free allocations (of only hydro resources) or MPB treatment (calculated only from hydro transactions) in each year.7 By adding back in the option of an allocation of hydro resources, Energy Division Staff will allow Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (SCE) to elect to continue the “interim” PG&E and SCE GHG-Free allocations, albeit without the non-hydro (i.e., nuclear) resource value.8 San Diego Gas & Electric Company (SDG&E) does not have “interim allocations,” and therefore would “choose” the GHG-Free MPB until it has an allocation process approved by the Commission.9 Through this Supplemental Proposal, Energy Division has methodically collected data demonstrating an incremental GHG-Free “value,” which the Supplemental Proposal provides to unbundled customers through its proposed methodology. CalCCA therefore supports the Supplemental Proposal, but has the following recommended modifications to ensure its effective application and compliance with statutory mandates:
• The frequency of an IOU’s election of an allocation or MPB should be limited to either a one-time or multi-year option to allow LSEs adequate time for long-term procurement and compliance planning; and
• To comply with the requirements of Public Utilities Code sections 366.2(g) and 365.2 requiring, the Commission should order the continuance of the separate interim allocations of non-hydropower (hydro), including nuclear allocation GHG-Free attributes, while monitoring the market for GHG-free non-hydro transactions.

If a market for such GHG-Free non-hydro transactions emerges, the Commission 7 Supplemental Proposal at 2.
8 See Supplemental Proposal at 2 (referencing Resolution E-5046 (May 7, 2020) (adopting an interim allocation of energy from GHG-Free resources (separated into buckets of nuclear and non-nuclear energy) to PCIA-eligible LSE’s in PG&E’s service territory, based on an individual LSE’s share of forecasted load in the service territory); Resolution E-5111 (Dec, 17, 2020) (extending the PG&E allocations through 2021, with the option to extend through 2022 and 2023); Resolution E-5095 (Aug. 28, 2020) (interim allocations in SCE territory through 2022); D.21-05-030, Phase 2 Decision on Power Charge Indifference Adjustment Cap and Portfolio Optimization, R.17-06-026 (May 24, 2021) Ordering Paragraph 12 at 67 (extending the SCE interim allocations through 2023) (collectively, the “Interim Allocations”)).
9 Supplemental Proposal at 3.
4 should then establish a non-hydro MPB, and adopt the Supplemental Proposal’s methodology for IOU elections of allocations or MPBs for hydro and non-hydro GHG-Free value.

B. Additional Issues in Scope
The Ruling also requests comments on whether the Commission should consider additional issues before closing this proceeding. Prior Commission decisions point to this proceeding as the appropriate venue to develop PCIA-related policies necessary to address issues that specific Energy Resource Recovery Account (ERRA) forecast and compliance proceedings were unable to resolve. Specifically, the Commission should address the following issues prior to closing this proceeding:
• The appropriate venue for determining vintaging changes when an IOU procurement contract is amended, renewed, or extended, which is the subject of a currently outstanding September Motion filed by CalCCA in this proceeding on September 9, 2022;10 and
• The urgent need for a permanent framework to credit the Portfolio Allocation Balancing Account (PABA) when utilities use banked Renewable Energy Certificates (RECs) for RPS compliance, which the Commission has noted in two decisions should be developed within this proceeding.11 As set forth more fully below, closing this proceeding without addressing these issues will:
(1) cause continued uncertainty; (2) further burden the ERRA expedited proceedings, which are not designed to address policy issues; and (3) risk the potential for inconsistent treatment of contract amendments and PABA revenue across IOU service territories. 10 California Community Choice Association’s Motion to Amend Assigned Commissioner’s Second Amended Scoping Memo and Ruling, R.17-06-026, at 1 (Sept. 9, 2022) (September Motion). 11 D.20-02-047 (PG&E 2020 ERRA Forecast proceeding), at 15-16; D.22-12-012 (SCE 2023 ERRA Forecast Proceeding), at 22.
5 II. THE SUPPLEMENTAL PROPOSAL SHOULD BE ADOPTED WITH

MODIFICATIONS
CalCCA supports the Supplemental Proposal, as it recommends providing unbundled customers with their proportional share of the incremental GHG-Free benefits/value for non-RPS eligible large hydropower resources. As set forth more fully below, however, two modifications should be made to the Supplemental Proposal to ensure its efficient application and comply with statutory mandates: (1) the annual election by the IOUs of either MPB treatment or GHG-Free allocations should be modified to either a one-time permanent or multi-year choice to allow LSEs adequate time for long-term planning; and (2) to comply with the requirements of Public Utilities Code sections 366.2(g) and 365.2, the Commission should order the continuance of the separate IOU “interim” allocations of non-hydro, nuclear GHG-Free attributes, monitor the market for non-hydro GHG-free attribute transactions, establish a non-hydro, nuclear GHG-Free MPB if a market emerges, and at that time add the non-hydro GHG-free value to the methodology proposed in the Supplemental Proposal (i.e., IOU election of allocation or MPB).

A. The Frequency of an IOU’s Election of an Allocation or MPB Should be Limited to Allow Adequate Time for LSE Long Term Procurement and Compliance Planning
The annual election by the IOUs of either MPB treatment or GHG-Free allocations should be modified to allow either a one-time permanent or multi-year election to provide LSEs adequate time to plan for their GHG-Free compliance and procurement needs. The Supplemental Proposal allows the IOUs to make their annual election for each calendar year in the IOU’s ERRA Forecast application filing for that year.12 While CalCCA is supportive of the Supplemental Proposal and allowing the IOUs to elect how it will provide the GHG-Free value/benefits, the Supplemental 12 For the 2024 ERRA Forecast application only, each IOU must make its election via a Tier 1 advice letter by June 15, 2023 and must revise its ERRA Forecast workpapers, as necessary, by July 15, 2023. See Supplemental Proposal at 2.
6 Proposal should be modified to only allow such an election one time on a permanent basis. LSEs need adequate time for procurement and other long-term planning, and the one-year election cycle fails to allow sufficient notice of the way in which the value or benefits of the GHG-Free resources will be provided. For example, if an IOU chooses the allocation one year, but then switches to the MPB the next year, the LSE may have failed to procure the GHG-Free resources needed to meet procurement and compliance obligations in that year that the allocation will have fulfilled. In the alternative, the IOU election should be allowed for a period of years, corresponding to a compliance period (such as the RPS three-year compliance period, or any compliance period that may be established given Senate Bill 100 goals and the potential development of a long-term reliability and GHG reduction procurement program in the Integrated Resource Plan (IRP) proceeding).

B. Statutory Requirements and the Prohibition Against Cost Shifting Require the Commission to Allow Unbundled Customers to Elect to Receive GHG-Free Value for Non-Hydro, Nuclear Resources
The Supplemental Proposal should be modified to allow unbundled customers to elect to receive the benefits for all GHG-Free resources, including nuclear, in the IOUs’ PCIA portfolios.

Public Utilities Code sections 366.2(g) and 365.2 require the Commission to ensure unbundled customers can receive the benefits of the resources they fund through the PCIA, and to ensure costs incurred by bundled customers are not shifted to unbundled customers (i.e., requiring unbundled customers to incur costs while bundled customers benefit). The Supplemental Proposal provides value only for hydro GHG-Free resources, either through an allocation or MPB (as elected by the IOUs). By omitting non-hydro attributes, including nuclear, however, the Supplemental Proposal fails to provide the full value required by Public Utilities Code sections 366.2(g) and 365.2. To ensure the equitable distribution of all GHG-Free value, the Supplemental 7 Proposal should be modified to incorporate the non-hydro, nuclear resources, as originally envisioned in the September 12 Staff Proposal.13
Given that Energy Division was unable to establish a MPB for the GHG-Free value of non-hydro, including nuclear, resources at this time given the small number of GHG-Free transactions involving such resources, CalCCA proposes the continuation of the separate interim allocations for the non-hydro, nuclear GHG-Free value until a MPB for non-hydro, nuclear can be established.14 Energy Division can monitor the GHG-Free non-hydro, nuclear transactions to determine if a market emerges enabling the establishment of a non-hydro, nuclear GHG-Free MPB. If such a MPB can be established, the methodology proposed in the Supplemental Proposal for the hydro resources (i.e., either allocation or MPB, as elected by the IOU) can then be applied to the non-hydro, nuclear resources. Continuing the separate interim allocations for non-hydro, nuclear and establishing the non-hydro, nuclear GHG-Free MPB when a market for such resources develops, in addition to the Supplemental Proposal for hydro GHG-free, will ensure that unbundled customers can elect to receive all GHG-free benefits in compliance with Public Utilities Code sections 366.2(g) and 365.2. If the Commission declines to allow unbundled customers to elect to receive all the GHG-Free value/benefits (including non-hydro, nuclear), it should ensure that all customers 13 See September 12 Staff Proposal, at 7 (“staff proposes to include transactions for in-CAISO and out-of-CAISO large hydro and nuclear resources”) (emphasis added). In addition, the September 2022 Staff Proposal recognizes that until PCIA funding for the Diablo Canyon Power Plant (DCPP) concludes (in November 2024 for Unit 1, and in 2025 for Unit 2), DCPP GHG-Free value will continue to be subject to the rules adopted in this proceeding. Id. at 8.
14 The dearth of reportable non-hydro, nuclear transactions is likely due to the limited number of nuclear suppliers in California, and the west in general. In addition, the non-hydro, nuclear GHG-free attributes have been offered by PG&E and Edison through the interim allocations, which significantly lowers the number of reportable transactions for GHG-Free non-hydro, nuclear attributes. However, if non-hydro, nuclear transactions increase, the Commission may at that point be able to establish the GHG-Free non-hydro, nuclear MPB. 8 receive equal treatment by denying the IOUs the use of the GHG-Free attributes for which it fails to provide unbundled customers value (i.e., non-hydro, nuclear GHG-Free), for any purpose.

III. THE COMMISSION SHOULD ADD TO THE PCIA PROCEEDING SCOPE

ISSUES REGARDING RE-VINTAGING IOU POWER PURCHASE

AGREEMENTS (PPA) AND CREDITING OF BANKED RECS
A. The Commission Should Grant CalCCA’s Outstanding September Motion in this Proceeding Regarding Re-vintaging IOU PPAs
CalCCA filed its September Motion to implement D.21-07-013 by amending the Scoping Ruling in this proceeding to include consideration of the appropriate venue for determining vintaging changes when an IOU procurement contract is amended, renewed, or extended.15 Contract amendments, renewals, and extensions may affect the vintage of ratepayers to whom the costs related to the amendment, renewal, or extension should be attributed for purposes of calculating the PCIA. Stakeholders are currently required to raise this issue in response to advice letters, which is an insufficient venue to consider the detail required to address vintaging.16 Although D.21-07-013 noted an intent to address within this proceeding the question of which venue is appropriate to consider re-vintaging of contract amendments, renewals, and extensions, the September Motion remains outstanding.

Currently, the only venue available for review of IOU contract amendments, renewals, and extensions for the purposes of proper cost recovery is the advice letter process.17 However, the inquiry requires more than what the advice letter process can provide. The specific question at issue with respect to vintaging, or re-vintaging, is whether a particular contract amendment, renewal, or extension constitutes a new procurement decision on behalf of currently bundled 15 September Motion at 1.
16 Id. at 2.
17 Id. at 5.
9 customers (and therefore warrants re-vintaging).18 Material contract terms, such as price, duration, and quantity underlie the inquiry but also are typically confidential and redacted from advice letter filings.

General Order 96-B, governing the advice letter process, does not provide for a formal discovery process – for any tier of advice letter.19 Therefore, unless there is an underlying docket under which a market participant like a CCA would have already signed an applicable non-disclosure agreement (NDA), the process to sign the NDA and submit discovery to obtain the previous and modified contracts would eat up much of the 20-day protest period. The September Motion cites to an example in which resolving whether a reviewing representative could sign an IOU’s NDA alone took over 20 days.20
Because of these procedural difficulties, a group of Northern California CCAs requested the issue of re-vintaging be addressed in PG&E’s 2019 ERRA Compliance case.21 In response to the CCAs’ raising the issue, the Commission recognized the need to take a closer look at where vintaging is best addressed:
[T]he Commission’s currently open proceeding, Order Instituting Rulemaking to Review, Revise, and Consider Alternatives to the Power Charge Indifference Adjustment, R.17-06-026, is more appropriate for considering how the Commission should address contract vintages for the utilities in the future, and we intend to explore these matters in that proceeding.22
18 Id. at 5. That inquiry is separate and distinct from review of the reasonableness of the amendment, renewal, or extension of a contract, and whether such contract action comports with Standard of Care 4 or the IOU’s Bundled Procurement Plan. Id. at 5. 19 Id. at 6.
20 Id. (citing to Joint CCA Opening Comments on Proposed Decision in PG&E’s 2019 ERRA Compliance proceeding).
21 Opening Comments of Joint Community Choice Aggregators on Proposed Decision Resolving Phase One of Pacific Gas and Electric Company’s Energy Resources Recovery Account (ERRA) Compliance Application for the 2019 Record Year, Application (A.) 20-02-009 (June 30, 2021) (“Joint CCA Opening Comments”).
22 D.21-07-013, Decision Resolving Phase One of Pacific Gas and Electric Company’s ERRA Compliance Application for the 2019 Record Year, A.20-02-009 (July 15, 2021), at 21 (emphasis added). 10 No party opposes the September Motion. AReM/DACC “strongly supports” the September Motion and agrees with both CalCCA’s analysis regarding contract re-vintaging and the fact there is no effective forum for these issues at present.23 The Joint IOUs do not oppose the request to include the issue in scope of this proceeding, observing that “[a] statewide rulemaking to review [PCIA] matters is an appropriate proceeding for the Commission to determine the appropriate venue to address vintaging matters applicable to PCIA-eligible contract amendments, renewals, and extensions.”24 The IOUs, however, do take issue with the September Motion’s characterization of CCA departing load cost responsibility,25 which is largely irrelevant to the procedural question at issue and was only offered by CalCCA as context to introduce the issue.26 The IOUs also argue that the advice letter process can be a robust stakeholder process to evaluate an IOU’s procurement contract approval and associated cost recovery request. 27 Such an argument, however, ignores the
problem CalCCA presents – that the short protest period, need to sign an NDA and the need to submit discovery are incompatible with the advice letter process.

While disagreement on these points likely still exists, the issue that would be decided in this proceeding is largely a procedural one – does the advice letter process provide sufficient mechanisms to allow for a review of whether an amended contract should be re-vintaged, or are ratepayers better served by the process afforded to parties in the ERRA compliance proceeding? Such a process question undoubtedly can be resolved via a short comment period, and, therefore, 23 Response of the Alliance for Retail Energy Markets and the Direct Access Customer Coalition to California Community Choice Association’s Motion to Amend Assigned Commissioner’s Second Amended Scoping Memo and Ruling, R.17-06-026, at 1-2 (Sept. 26, 2022). 24 Joint Response of Pacific Gas and Electric Company (U 39-E), Southern California Edison Company (U 338-E), and San Diego Gas & Electric Company (U 902-E) to Motion to Amend Assigned Commissioner’s Second Scoping Memo and Ruling, R.17-06-026, at 1 (Sept. 26, 2022) (“IOU Response”). 25 Id. at 2-7.
26 See September Motion at 3-4.
27 IOU Response at 5-7.
11 granting CalCCA’s motion would not unduly extend the scope or timeline of this proceeding prior to its closure.

B. An Urgent Need Exists for a Permanent Framework to Credit the PABA When Utilities Use Banked RECs for RPS Compliance
The use of banked RECs to meet the IOUs’ RPS compliance requirements escalated in the past few years, requiring the development of interim solutions to account for that use within each IOU’s PABA. While parties have largely agreed on the interim solutions proposed within the PG&E and SCE ERRA forecast cases, the development of a permanent framework to value banked RECs as Retained RPS is both necessary and urgent, as the Commission has already acknowledged. Both the existing Voluntary Allocation and Market Offer (VAMO) process and proposed programs, such as SCE’s Green Share program, will further increase demand for RECs from the IOUs’ RPS-eligible portfolios, likely leading to an increased use of banked RECs to meet RPS compliance obligations in the near term. As set forth below, in two separate decisions, the Commission has stated the development of a REC-crediting framework is, or should be, within the scope of this proceeding.

The issue first arose in 2019. In its 2020 ERRA Forecast case, PG&E forecasted it would oversell its RPS generation within the 2020 forecast year, requiring the utility to utilize banked RECs to meet its compliance requirements.28 Decision 20-02-047 determined such RECs should be valued at the RPS Adder, but acknowledged that R.17-06-026 is the proper place to address a longer-term framework:

A tracking framework within PABA and mechanisms to value banked RECs at the end of the compliance period may help resolve these issues. These issues are however, more appropriately addressed by the Commission in the PCIA proceeding.29
28 D.20-02-047, at 13-16.
29 Id. at 15-16.
12 The issue next arose in each of the utilities’ 2023 ERRA forecast cases, where the VAMO left all three IOUs short of the RPS-generation necessary to meet compliance requirements. SCE’s October Update proposed a three-step process to determine how to calculate how many banked RECs it would need for bundled customer compliance after the VAMO.30 That process resulted in SCE estimating it will be short of the RECs needed to meet its 2023 RPS compliance requirement.31 PG&E similarly forecasted it would be short,32 and SDG&E’s October Update made clear it also would be short.33
During both PG&E’s 2020 ERRA Forecast case and again during the 2023 ERRA Forecast cases for PG&E and SCE, parties largely arrived at an agreement on the rate recovery for RECs that had been generated in prior years but used for compliance in later years. The solutions revolved around how to value within the PABA banked RECs being used as Retained RPS in the forecast year that had previously been valued at a different amount in the year in which they were generated. In SCE’s case, for example, SCE determined there were sufficient banked RECs that it had previously valued as Unsold RPS, i.e., valued at $0, to cover the shortfall it anticipated in meeting its RPS compliance obligation.
34 SCE applied the 2023 Forecast RPS Adder to these
banked RECs since they were forecasted to be retained for bundled customer’s RPS compliance,35 essentially converting the banked RECs from Unsold RPS to Retained RPS. Similarly, parties agreed on PG&E’s approach to “true-up” the value of RECs previously valued as Retained RPS in a prior case to the value those same RECs would realize under the 2023 Forecast RPS Adder. 30 A.22-05-014, Exh. SCE-05 at 122:15-124:3.
31 Id., Exh. SCE-05 at 123:16-124:3 (the exact amount is confidential). 32 A.22-05-029, Exh. D.22-12-044 at 22. SDG&E’s case is addressed infra. 33 Comments of San Diego Community Power and Clean Energy Alliance on the October Update of San Diego Gas & Electric Company, A.22-05-025, at 6-11 (Oct. 28, 2022). 34 A.22-05-014, Exh. SCE-05 at 123:16-124:3.
35 Id., Exh. SCE-05 at 123:16-124:3.
13 The Southern California (SoCal) CCAs agreed with SCE’s interim methodology and the figures resulting from that methodology,36 and the Commission adopted it in D.22-12-012.37 CalCCA agreed with PG&E’s interim methodology, and the Commission adopted it in D.22-12- 044. 38 While SDG&E’s October Update clearly showed a post-VAMO shortfall in RPS to meet its compliance obligation, and the CCAs put forward the same solution agreed upon in the other ERRA forecast cases in their October Update comments, the utility argued the issue was out of scope. The Commission opted not to bring its SDG&E decision in line with its PG&E and SCE decisions.39 Lastly, in A.22-05-022, et al., SCE has proposed what is essentially a REC-purchasing program to replace the Green Tariff Shared Renewable Program.40 Under SCE’s proposal, participating bundled service customers will remain on their otherwise applicable tariff and will pay the cost of their participation in SCE Green Share through an adder rate on their bill.41 SCE has stated Green Share “will use SCE’s renewable energy portfolio, in excess of what is required to meet SCE’s RPS compliance requirements or other CPUC mandated procurement programs, which could potentially include banked PCC-1 RECs.”42 PG&E has proposed a nearly identical program.43 While fact-finding is still on-going in that proceeding, and parties’ proposals are not yet final, CalCCA currently foresees both programs using banked RECs to meet customer demand, if they are adopted.
36 D.22-12-012, at 60.
37 Id. at 61.
38 D.22-12-044, at 22.
39 D.22-12-042, at 21-22.
40 A.22-05-022, et al., Exh. SCE-02 at 12-30.
41 A.22-05-022, et al., Exh. SCE-02 at 12:16-17, 30:3-7. 42 A.22-05-022, et al., Exh. SCE-02 at 21:2-4; 27:10-12. 43 Pacific Gas and Electric Company Green Access Programs (GAP) Evaluation and Proposals Application for Review Disadvantaged Communities-Green Tariff (DAC-GT), Community Solar-Green Tariff (CS-GT), and Green Tariff Shared Renewables (GTSR) Supplemental Testimony, A.22-05-022, et al., at 12-25 (Jan. 20, 2023).
14 The problem, as SCE acknowledged in its ERRA Forecast case, is that the accounting framework is only a temporary solution.44 Noting D.20-20-047 had already addressed the issue, the SoCal CCAs argued that a permanent framework to credit banked RECs should be developed in the PCIA proceeding to ensure all RPS energy is appropriately valued in the PCIA.45 In response, the Commission stated: “… the current scope of the PCIA proceeding includes consideration of whether to modify or clarify the calculation of the PCIA for VAMO transactions, so we do not address SoCal CCAs’ request here.”46 In PG&E’s case, the Commission acknowledged that “CalCCA and PG&E have agreed there should be a framework for handling banked renewable energy credits for the post-2023 period,” but stated the issue was out of scope in that case.47 The Commission’s ERRA decision for SDG&E stated “SDCP and CEA are … free to raise this issue in R.17-06-026 if they elect to do so.”48 The Commission should act on D.20-02-047 and D.22-12-012 to order the development of a framework to credit banked RECs in this proceeding. The issue affects all three utility service territories and requires a consistent solution across IOUs. The disparate outcomes within the ERRA Forecast proceedings – indeed, the fact all three decisions were unable to come to agreement on whether the issue should even be addressed – are evidence of the need for one consistent policy applicable to all three IOUs. That policy should be developed in a proceeding in which all three IOUs are parties.

CalCCA urges the Commission to address this issue before it closes this proceeding. The framework should include issues such as a ‘lookback’ period over which the IOU can go back to 44 A.22-015-014, Exh. SCE-05 at 123:16-124:3
45 Id., Exh. CCA-01 at 32:3-6.
46 D.22-12-012, at 61 (emphasis added).
47 D.22-12-044, at 22.
48 D.22-12-042, at 22.
15 use excess RECs, the quantity of excess RECs that can be used from each vintage, what to do if there are insufficient excess RECs available, the value that will be placed on the RECs, and specific methodologies for tracking excess RECs and whether they have been previously charged to customers. To date, the CCA and IOU parties (excluding SDG&E) have been able to find agreement on interim versions of such a framework, and there is no reason to believe a workshop and comment period could not resolve any remaining differences in an efficient manner.

IV. CONCLUSION
For all the foregoing reasons, CalCCA respectfully requests adoption of the recommendations set forth in these Comments. To the extent the Commission closes R.17-06-026 without addressing the two issues recommended to be added to the proceeding scope discussed herein, CalCCA urges the Commission to quickly open a successor proceeding to address them, or to prescribe in detail the appropriate venue in which they can be raised in the near term.

Respectfully submitted,
Evelyn Kahl,
General Counsel and Director of Policy

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
March 17, 2023
March 21, 2023

VIA ELECTRONIC MAIL
Ms. Leuwam Tesfai
Deputy Executive Director, Energy and Climate Policy
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102
Re: California Community Choice Association’s Protest of Pacific Gas and Electric Company’s Tier 3 Advice Letter 6870-E: Establish the Diablo Canyon Transition and Relicensing Memorandum Account and the Diablo Canyon Extended Operations Balancing Account in Compliance with Decision 22-12-005
Dear Ms. Tesfai,
Pursuant to the California Public Utilities Commission’s (Commission’s) General Order (GO) 96-B,1
the California Community Choice Association2 (CalCCA) hereby submits this protest of Pacific Gas and Electric Company’s (PG&E) Tier 3 Advice Letter 6870-E3: Establish the Diablo Canyon Transition and Relicensing Memorandum Account and the Diablo Canyon Extended Operations Balancing Account in Compliance with Decision 22-12-005 (Advice Letter). CalCCA files this protest to propose modest changes to certain language within PG&E’s proposed preliminary statements to clarify the accounting procedures tied to the cost recovery of extended operations of Diablo Canyon Power Plant (DCPP).

BACKGROUND
PG&E filed the Advice Letter on March 1, 2023, in response to Decision (D.) 22-12- 005,4 which ordered PG&E to file a Tier 3 Advice Letter to provide a detailed and complete 1 References to “General Rules” are to the general rules identified in General Order 96-B:
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M023/K381/23381302.PDF. 2 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Baldwin Park Resident Owned Utility District, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Desert Community Energy, East Bay Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Choice Energy, Marin Clean Energy, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 3 PG&E’s Advice Letter 6870-E: Establish the Diablo Canyon Transition and Relicensing Memorandum Account and the Diablo Canyon Extended Operations Balancing Account in Compliance with Decision 22-12-005, Mar. 1, 2023: https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC_6870-E.pdf. 4 D.22-12-005, Decision Implementing Senate Bill 846, Application 16-08-006 (Dec. 6, 2022):
https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M499/K622/499622197.PDF.

Ms. Leuwam Tesfai

March 21, 2023
accounting structure of the associated costs and recovery of DCPP under Senate Bill (SB) 846.

That structure consists primarily of two balancing accounts: the Diablo Canyon Transition and Relicensing Memorandum Account (DCTRMA) and the Diablo Canyon Extended Operations Balancing Account (DCEOBA).5 Prior to filing the Advice Letter, PG&E held a meet and confer with CalCCA and other parties on February 6, 2023, regarding the contents of the Advice Letter, and PG&E appended CalCCA’s comments on the meet and confer to the Advice Letter itself.

Also relevant to the Commission’s disposition of the Advice Letter, the Commission issued an order instituting Rulemaking (R.) 23-01-007 to address implementation of SB 846 OIR. 6 PROTEST
CalCCA protests the Advice Letter pursuant to Section 7.4.2(6) of GO 96-B, which allows protests on the grounds the relief requested in the advice letter is unreasonable. While the Advice Letter largely and appropriately addresses a number of issues CalCCA raised, the DCEOBA preliminary statement requires two small changes to bring it in line with reasonable accounting practices (and likely, also in line with PG&E’s intent).

1. Two Changes to PG&E’s Preliminary Statements Will More Clearly Align PG&E’s Proposed Accounting Practices
There are two small issues that require clean up prior to disposition of the Advice Letter.

First, the Extended Operations Subaccount accounting procedure in the DCEOBA allows for a debit entry equal to incurred replacement power costs.
7 It should also allow for a credit entry to
reverse replacement power costs (and transfer them to the Liquidated Damages Subaccount) if incurred during outages where PG&E is found not to have met the reasonable manager standard.

The Liquidated Damages Subaccount already allows for the debit side of this transfer, as written,8
so it appears PG&E intended for a corresponding credit to be recorded to the Extended Operations Subaccount. Modifications to accomplish this end are:

EXTENDED OPERATIONS SUBACCOUNT (Six Sub-Accounts):
…
c. A credit entry equal to incurred replacement power costs as directed by the Commission;
…
5 Id., at Ordering Paragraph 4.
6 Order Instituting Rulemaking to Consider Potential Extension Of Diablo Canyon Power Plant Operations in Accordance With Senate Bill 846, R.23-01-007 (Jan. 12, 2023) (SB 846 OIR). 7 Advice Letter at Electric Preliminary Statement Part JR, Extended Operations Subaccount, Section 5.d.
8 Advice Letter at Electric Preliminary Statement Part JR, Liquidated Damages Subaccount, Section 5.b.

Ms. Leuwam Tesfai

March 21, 2023
Section 5.n states: “A debit or credit entry, as appropriate, to record the transfer of amounts to or from other accounts, upon approval by the Commission.” While Section 5.n may be a “catch-all” to address the issue CalCCA raises here, it is clearer to include a corresponding credit if the debit is expressly provided for within the Liquidated Damages Subaccount.

Second, the following underlined language should be added to the Volumetric Performance Fee Subaccount accounting procedure 5.b: “A credit entry equal to net revenues and charges received in the CAISO market related to the extended operation of the Diablo Canyon Power Plant, to the extent such net revenue and charges are in excess of the amount recorded to the Extended Operations Subaccount.” 9 The addition clarifies the “waterfall” for applying CAISO market revenues against different types of costs discussed in Section 3 of this protest.

2. PG&E Addresses the Impact the SB 846 OIR Will Have on the Advice Letter PG&E responded to a number of concerns raised in CalCCA’s comments. Most importantly, PG&E acknowledges:
[T]he draft preliminary statements for the DCTRMA and DCEOBA are subject to change through CPUC action in R.23-01-007. PG&E concurs that the DCEOBA specifically is subject to change based on the CPUC’s action in R.23-01-007 and has included this language above in the “Overview” of the DCEOBA section included within Tariff Updates.10
This language addresses a key risk from two parallel processes. The first process is where PG&E filed the Advice Letter, for Commission disposition. The second process is in the pending SB 846 OIR where the relief requested in the Advice Letter may be modified.

For example, removing DCPP from the Power Charge Indifference Adjustment is likely to change how PG&E’s procurement department costs are allocated, an issue currently not reflected within the Advice Letter. Another issue relates to the “standard overheads” in the Advice Letter. Currently, PG&E treats DCPP as its own subfunction of PG&E’s electric line of business general rate cases (GRC). As a result, PG&E allocates to DCPP a portion of corporate administrative and general (A&G) overhead costs when determining revenue requirement related to DCPP. If PG&E continues to operate DCPP, and the mechanism for recovering DCPP costs changes, then corporate A&G overhead costs should continue to be allocated to DCPP. The Advice Letter does not appear to reflect that continued allocation currently. These issues may be 9 Advice Letter at Electric Preliminary Statement Part JR, Volumetric Performance Fee Subaccount, Section 5.b.
10 Advice Letter at 7.

Ms. Leuwam Tesfai

March 21, 2023
addressed in the SB 846 OIR, and the cost recovery language in the Advice Letter may need to change based on the SB 846 OIR’s outcome.

3. PG&E’s Advice Letter Clarifies Important Details of DCPP Subaccounts The utility also provides further clarity on the accounting “waterfall” applied to market revenues from the California Independent System Operator. It states such revenues would be credited first to Extended Operations subaccount, the balance of which is paid by customers of all load-serving entities (LSEs) in California, and then to the Volumetric Performance subaccount, which is paid only by LSEs in PG&E’s service territory.11 PG&E further clarifies that no CAISO market revenues will be recorded to the Liquidated Damages Subaccount.

CalCCA agrees with both treatments.

In response to CalCCA’s comments, PG&E also defines “incremental costs” as “costs that are incremental to what is authorized for cost recovery through another proceeding such as PG&E’s GRC proceeding or PG&E’s Nuclear Decommissioning Cost Triennial proceeding.”12 CalCCA does not object to this definition.

CONCLUSION
CalCCA thanks the Energy Division for its review of this protest, and respectfully requests it order PG&E to modify the preliminary statements to reflect the issues raised in this protest.

Respectfully,

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
Evelyn Kahl
General Counsel and Director of Policy
cc via email:

Energy Division Tariff Unit ([email protected])
Sidney Bob Dietz II ([email protected])
Service Lists: A.16-08-006, A.21-12-007, A.22-02-016, R.20-05-003 and R.23-01-007 11 Advice Letter at 8.
12 Advice Letter at 7.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric
Company for Approval of 2024-2031
Energy Efficiency Business Plan and 2024-
2027 Portfolio Plan. (U 39 M)
Application 22-02-005
(Filed February 15, 2022)
And Related Matters.

Application 22-03-003
Application 22-03-004
Application 22-03-005
Application 22-03-007
Application 22-03-008
Application 22-03-011
Application 22-03-012
(Consolidated)

OPENING COMMENTS OF MARIN CLEAN ENERGY ON PROPOSED DECISION

ADDRESSING CODES AND STANDARDS SUBPROGRAMS AND BUDGETS AND

STAFF PROPOSAL ON REDUCING RATEPAYER-FUNDED INCENTIVES FOR GAS

ENERGY EFFICIENCY MEASURES
Wade Stano
Policy Counsel

MARIN CLEAN ENERGY
1125 Tamalpais Ave San Rafael, CA 94901
Telephone: (415) 464-6024
Email: [email protected]
March 23, 2023
Opening PD Comments of MCE
i
Subject Index
I. Introduction ........................................................................................................................... 1 II. MCE Supports Strategies to Ensure Equity Segment Participants Benefit from Energy Efficiency Programs and Decarbonization Policies ................................................................... 2 III. MCE Requests the Commission Clarify Which Building Retrofit Projects Constitute “New Construction”……………………..……….………………….…………………………...4
IV. Conclusion………………………………………………………..……………………..…..5
Opening PD Comments of MCE
ii
Table of Authorities
Commission Rules of Practice and Procedure
Rule 14.3...................................................................................................................................1.

Commission Decisions
Proposed Decision A.22-02-005 et al (03/03/2023) ………………..……...6, 11, 19-21, 24, 31.

Opening PD Comments of MCE
1 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric
Company for Approval of 2024-2031
Energy Efficiency Business Plan and 2024-
2027 Portfolio Plan. (U 39 M)
Application 22-02-005
(Filed February 15, 2022)
And Related Matters.

Application 22-03-003
Application 22-03-004
Application 22-03-005
Application 22-03-007
Application 22-03-008
Application 22-03-011
Application 22-03-012
(Consolidated)

OPENING COMMENTS OF MARIN CLEAN ENERGY ON PROPOSED DECISION

ADDRESSING CODES AND STANDARDS SUBPROGRAMS AND BUDGETS AND

STAFF PROPOSAL ON REDUCING RATEPAYER-FUNDED INCENTIVES FOR GAS

ENERGY EFFICIENCY MEASURES
I. Introduction
Pursuant to Rule 14.3 of the Rules of Practice and Procedure of the California Public Utilities Commission (“Commission” or “CPUC”), Marin Clean Energy (“MCE”), respectfully submits these Opening Comments on the Proposed Decision Addressing Codes and Standards Subprograms and Budgets and Staff Proposal on Reducing Ratepayer-Funded Incentives for Gas Energy Efficiency Measures (“Proposed Decision” or “PD”) mailed on March 03, 2023. MCE supports the Commission taking essential steps to further integrate the state’s decarbonization goals and policies into ratepayer-funded energy efficiency (“EE”) programs. Correspondingly, MCE supports the Commission reducing and ultimately eliminating EE incentives for natural gas Opening PD Comments of MCE
2 measures.1 MCE specifically supports the Commission’s approach to ensuring Equity segment participants (“Equity customers”2
) maximally benefit from EE programs and decarbonization policies throughout California’s energy transition. MCE recommends additive community engagement, program integration, and resource identification strategies to support an equitable implementation of the PD. MCE additionally requests the Commission clarify which existing building retrofit projects constitute “new construction” and are included in its “policy for new construction projects.”3 MCE looks forward to collaborating with the Commission, program administrators and stakeholders on implementation and actionable, sustainable, affordable, safe, healthy, regionally specific and equitable pathways to building decarbonization.

II. MCE Supports Strategies to Ensure Equity Segment Participants Benefit from Energy Efficiency Programs and Decarbonization Policies MCE strongly supports the Commission adopting ambitious and equitable decarbonization policies in its EE programs. MCE agrees with the Commission that significant data gaps exist about the precise infrastructure needs, costs and strategies required for Equity segment customers to access and benefit from residential electrification measures.4 MCE additionally agrees with the Commission that Equity segment customers likely may require additional, dedicated incentives and supporting measures to benefit from electrification measures. 5 1
Natural gas measures defined pursuant to the PD and thereby excluding “exempt measures” that produce gas savings, but do not burn gas. PD at p. 9. 2 MCE refers to all categories of customers eligible for its proposed Equity segment programs using the umbrella term “Equity customers.” See Application of Marin Clean Energy for Approval of 20024-2031 Energy Efficiency Business Plan and 2024-2027 Energy Efficiency Portfolio Plan, Exhibit 2, Chapter 3, Section 4.2. MCE defines “Equity customers” as residential customers and businesses in ESJ communities.” “ESJ communities” defined by the Commission’s ESJ Action Plan (2019; 2022).
3 PD at pp. 19-21.
4 PD at p. 24.
5 PD at p. 6.

Opening PD Comments of MCE
3 As MCE stated in its Opening Comments responding to Administrative Law Judge’s Ruling Inviting Comments on Staff Proposal for Gas Energy Efficiency Incentives and Codes and Standards Sub-Programs and Budgets, Equity segment customers experience both serious disproportionate health impacts from natural gas appliances and significant energy burdens.6 Due to the information gaps and potential risks to Equity segment customers, MCE supports the Commission preserving natural gas incentives for Equity customers until the information and resources are available to ensure their beneficial participation in EE programs without them. MCE supports working to close these critical information gaps through the proposed fuel substitution infrastructure costs for low-income customers study, market rate customer fuel substitution market study, and low-income customer fuel substitution market study.7

MCE recommends the Commission require these studies to include meaningful community engagement strategies with equity stakeholders who are the best experts on the barriers and potential solutions to the varied barriers to fuel-substitution they experience.8 MCE further recommends the Commission expand the scopes of these studies to include proposals for how complimentary local, state and federal decarbonization resources may support low-income and 6 Opening Comments of MCE on Administrative Law Judge’s Ruling Inviting Comments on Staff Proposal for Gas Energy Efficiency Incentives and Codes and Standards Sub-Programs and Budgets (“Staff Proposal”) at pp. 7-9.
7 PD at p. 24.
8 ESJ Action Plan (2022), available at:
https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/news-and-outreach/documents/news-office/key-issues/esj/esj-action-plan-v2jw.pdf (Goal 5: “Enhance Outreach and Public Participation Opportunities for ESJ Communities to Meaningfully Participate in the CPUC’s Decision-Making Process and Benefit from CPUC Programs.”).

Opening PD Comments of MCE
4 Environmental and Social Justice (“ESJ”)9 community fuel substitution.10 The studies should identify potential complementary funding and programmatic resources to cover low-income and ESJ fuel-substitution costs. In addition, the studies should include potential program integration policies required for successful implementation of fuel substitution and decarbonization measures.

MCE further supports requiring all program administrators (“PAs”) to develop “comprehensive strateg[ies]”11 in collaboration with equity stakeholders through community engagement and pilots to identify and mitigate Equity segment sector specific barriers to electrification.

III. MCE Requests the Commission Clarify Which Building Retrofit Projects Constitute “New Construction”
MCE supports the Commission’s “new construction”12 proposal to eliminate EE natural gas incentives in several circumstances. The PD relies on the California Energy Commission’s classification of new construction, “The California Energy Commission (CEC) classifies many existing building retrofits as new construction, which means some buildings to which our new construction policy would apply…”13 In order to prevent any confusion in the implementation of this PD, MCE recommends the Commission include the precise citation and controlling definition 9 “ESJ communities” defined by the Commission’s ESJ Action Plan (2022), available at:
https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/news-and-outreach/documents/news-office/key-issues/esj/esj-action-plan-v2jw.pdf. 10 See also Opening Comments of MCE on Staff Proposal at pp. 5-6 (including, but not limited to the California Energy Commission’s Equitable Building Decarbonization Program, Department of Energy’s Home Energy Rebate programs etc.). 11 PD. at p. 11. 12 PD at p. 19.
13 PD at pp. 20, 31 (COL 7)(“Similarly in its Conclusions of Law the Commission states, “7. For the purpose of determining whether to eliminate ratepayer funds for gas energy efficiency measures, it is reasonable to treat existing building retrofits that will not result in a substantial increase in gas consumption, which the CEC may classify as new construction, consistent with our policy for retrofits.”).

Opening PD Comments of MCE
5 of “new construction”14 and how it relates to retrofit projects of existing buildings in this Decision.

The definition of “new construction” continues to be an evolving issue across several related local, state, and federal venues. PAs, implementers, and EE program participants will benefit from greater clarity on this key definition.

IV. Conclusion
MCE thanks Commissioner Shiroma, Administrative Law Judge Fitch, Administrative Law Judge Kao, Energy Division staff and commenters for the robust discussion on natural gas incentives and their commitment to advancing beneficial and equitable decarbonization strategies in this PD.

Dated: March 23, 2023. Respectfully submitted,

14 The PD cites the 2022 Energy Code specifically. However, if the Commission is relying on additional and/or specific Codes and/or Sections, MCE recommends their explicit inclusion in this Decision. PD at p. 20.
/s/ Wade Stano
Wade Stano
Policy Counsel

MARIN CLEAN ENERGY
1125 Tamalpais Avenue
San Rafael, CA 94901
Telephone: (415) 464-6024
Email: [email protected]
Opening PD Comments of MCE
6 APPENDIX A –
RULE 14.3 (B) TO OPENING COMMENTS OF MARIN CLEAN ENERGY ON

PROPOSED DECISION ADDRESSING CODES AND STANDARDS SUBPROGRAMS

AND BUDGETS AND STAFF PROPOSAL ON REDUCING RATEPAYER-FUNDED

INCENTIVES FOR GAS ENERGY EFFICIENCY MEASURES
MCE respectfully proposes the following modifications to the Proposed Decision’s Conclusions of Law and Ordering Paragraphs. MCE exclusively included those Conclusions of Law and Ordering Paragraphs in which it proposes changes. MCE includes its proposed changes in red font below.

Conclusions of Law

2. Within 60 days after the issue date of this decision, the program administrator lead for each non-exempt natural gas new construction measure, whether it is Pacific Gas and Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, Southern California Gas Company, Bay Area Regional Energy Network, Southern California Regional Energy Network, Tri-County Regional Energy Network, Inland Regional Energy Network, or Marin Clean Energy, must file a document that identifies the Total Resource Cost benefit to cost ratio (based on the Cost Effectiveness Tool) for each permutation of non-exempt natural gas new construction measures, defined pursuant to the [controlling Code(s) Section(s)], with all available known costs.

7. For the purpose of determining whether to eliminate ratepayer funds for gas energy efficiency measures, it is reasonable to treat existing building retrofits that will not result in a substantial increase in gas consumption, which the CEC may classify as new construction, consistent with our policy for retrofits. Pursuant to the [controlling Code(s) Section(s)], the CEC defines new construction as…
Ordering Paragraphs

7. Pacific Gas and Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, and Southern California Gas Company (together, the investor-owned utilities or IOUs) must fund market studies on: (a) infrastructure costs needed for electrification for low-income customers; (b) the impact of incentives on customer fuel substitution for market rate customers; and (c) the impact of incentives on customer fuel substitution for low-income customers. The studies should include proposals for how complimentary local, state and federal decarbonization resources may support low-income and Environmental and Social Justice (“ESJ”) community fuel substitution. The IOUs must conduct community engagement with equity stakeholders in preparing a study on the impact of incentives on customer fuel substitution for low-income customers. For each of these three studies, the IOUs must publish and serve a draft by no later than December 31, 2023, and a final report by no later than March 1, 2024. The IOUs shall seek public comment by posting the draft report to the Public Document Area (https://pda.energydataweb.com) and follow the same process for evaluation studies before finalizing. The IOUs may recover up to $200,000 for the cost to produce each of these three studies.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Review,
Revise, and Consider Alternatives to the
Power Charge Indifference Adjustment. Rulemaking 17-06-026

CORRECTED MARIN CLEAN ENERGY REPLY COMMENTS ON
ADMINISTRATIVE LAW JUDGE’S RULING REQUESTING COMMENTS ON

SUPPLEMENTAL GREENHOUSE GAS-FREE PROPOSAL AND ISSUES IN SCOPE
Sabrinna Soldavini
Policy Analyst

MARIN CLEAN ENERGY
1125 Tamalpais Ave
San Rafael, CA 94901
Telephone: (415) 464-6670
Dated: 3/30/2023
1 TABLE OF CONTENTS
I. INTRODUCTION .............................................................................................................. 2 II. THE COMMISSION SHOULD ASSIGN AN MPB TO ALL GHG-FREE RESOURCES

AND IN THE INSTANCE A CCA DOES NOT ACCEPT ITS NUCLEAR

ALLOCATION, THE COMMISSION SHOULD APPLY THE MPB TO THE
UNELECTED ALLOCATIONS ........................................................................................ 2 III. CONCLUSION................................................................................................................... 5 2 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Review,
Revise, and Consider Alternatives to the
Power Charge Indifference Adjustment.

R.17-06-026

CORRECTED MARIN CLEAN ENERGY'S REPLY COMMENTS ON ADMINISTRATIVE LAW JUDGE’S RULING REQUESTING COMMENTS ON SUPPLEMENTAL

GREENHOUSE GAS-FREE PROPOSAL AND ISSUES IN SCOPE
Marin Clean Energy (“MCE”) submits these reply comments in response to Administrative Law Judge’s Ruling Requesting Comments on Supplemental Greenhouse Gas-Free Proposal and Issues in Scope issued in the instant proceeding.

I. INTRODUCTION
MCE, California’s first community choice aggregator (“CCA”), is a not-for-profit public agency that began service in 2010 with the goals of providing cleaner power at stable rates to its customers, reducing greenhouse emissions, and investing in energy programs that support communities’ energy needs. MCE is a load-serving entity serving approximately 1,200 MW peak load, providing electricity generation services to more than 1.1 million people in 37 member communities across four Bay Area counties.

II. THE COMMISSION SHOULD ASSIGN AN MPB TO ALL GHG-FREE

RESOURCES AND IN THE INSTANCE A CCA DOES NOT ACCEPT ITS

NUCLEAR ALLOCATION, THE COMMISSION SHOULD APPLY THE MPB

TO THE UNELECTED ALLOCATIONS
Both California Community Choice Association (“CalCCA”) and Southern California Edison (“SCE”) note in their comments that if an Investor Owned Utility (“IOU”) elects to offer 3 an allocation, voluntary allocations of nuclear should be permitted as well. 1,2 As CalCCA notes,
Public Utilities Code sections 366.2(g) and 365.2 require the Commission to ensure unbundled customers can receive the benefits of the resources they pay for and creates a prohibition against cost shifting.3
MCE agrees with CalCCA that the exclusion of non-hydro (nuclear) resources in both the allocation and Market Price Benchmark (“MPB”) is concerning and would violate the prohibition against cost shifting. MCE also agrees with SCE and CalCCA that if voluntary allocations continue, separate nuclear allocations that allow LSE’s to decline or accept nuclear allocations (but still accept large hydro allocations) should be offered. MCE believes that this is a necessary condition to not violate the prohibition against cost shifting; however, MCE does not believe that this condition alone is sufficient to ensure all LSE’s are able to receive the full benefits of nuclear resources that they pay for through the Power Charge Indifference Adjustment (PCIA).

In addition to offering a voluntary nuclear allocation, MCE recommends that the Commission assign a MPB to all GHG-Free resources, and in the instance that a CCA does not take its nuclear allocation, the Commission should apply the MPB to that nuclear allocation. This would then serve as an offset to the PCIA, allowing customers to receive the full benefits of these resources and recognizing local government authority.

For example, MCE’s Governing Board has adopted a policy to not make unit purchases of nuclear energy as part of its resource portfolio.4 This means that MCE cannot accept allocations of nuclear resources. Under the current GHG-Free allocation framework (and if the same allocation framework is extended), MCE’s customers cannot receive the full benefit of 1 SCE Opening Comments at 3-4.
2 CalCCA Opening Comments at 6. 3 CalCCA Opening Comments at 6-7. 4 MCE Board of Directors Resolution No. 2011-09.
4 nuclear resources they pay for – violating the prohibition against cost shifting. The fact that some CCAs could not, or chose not to, accept their nuclear allocation in the past does not mean that these resources have no GHG-Free value, only that the CCA used their statutory authority to control their procurement choices. This does not mean that their customers should not be made whole for the resources that they pay for through the PCIA. MCE believes that the simplest way to ensure customers receive the full benefit of these resources is to apply a GHG-Free benchmark to nuclear allocations that are not accepted.

While MCE understands concerns of including nuclear resources in the GHG-Free MPB due to a lack of reportable nuclear transactions, the lack of transactions does not mean that these resource attributes have no value. As pointed out by the Alliance of Retail Energy Markets/Direct Access Customer Coalition (“AReM/DACC”), some Electric Service Providers and CCAs have elected to take their nuclear allocations, highlighting that there is in fact a value.5 Additionally, it is worth noting that the lack of transactions is due to the limited number of suppliers and the fact that these resources have previously been offered through an allocation (rather than solicitation) process. The fact that the value is difficult to quantify does not mean that there is no value, and MCE believes that using the GHG-Free MPB as a proxy for a nuclear MPB to value the allocations is reasonable at this time to ensure that CCA customers can receive the full value of these resources.

MCE notes that in the case of Pacific Gas & Electric (PG&E) and their sole nuclear resource, Diablo Canyon, this treatment would only be needed until Diablo Canyon is removed from the PCIA (likely after 2025). As there are potentially only two years’ worth of nuclear allocation periods remaining for PG&E CCAs, the Commission must act now to assign a GHG-5 Opening Comments of AReM/DACC at 2. 5 Free MPB to nuclear resources. To do otherwise would continue an ongoing cost shift and result in customers like MCE’s not receiving the full benefit of the attributes they pay for. While MCE understands that there is disagreement over the value of nuclear GHG free attributes, the value is certainly non-zero. Continuing to allow the IOUs to keep the nuclear GHG free attributes when some CCAs are unable to accept them does not meet statutory requirements.

III. CONCLUSION
MCE thanks the Commission for its consideration of this request. For the reasons set forth above, MCE asks that the Commission adopt MCE’s recommendation to assign an MPB to all GHG-Free resources, and in the instance a CCA does not accept its nuclear allocation, apply the MPB to the unelected nuclear allocations.

Respectfully submitted,
Dated: 3/30/2023
/s/Sabrinna Soldavini
Sabrinna Soldavini
Policy Analyst

MARIN CLEAN ENERGY
1125 Tamalpais Avenue
San Rafael, CA 94901
Telephone: (415) 464-6670

APRIL FILINGS
MCE Advice Letter 69-E
1 April 3, 2023
California Public Utilities Commission
Energy Division
Attention: Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, CA 94102-3298
MCE Advice Letter 69-E
RE: 2024 Budget Request and Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff and the Community Solar Green Tariff Programs
Pursuant to Ordering Paragraphs (“OP”) 2 and 4 of Resolution E-4999,1 and OP 3 of Resolution E-5125,2 Marin Clean Energy (“MCE”) hereby submits this Tier 2 Advice Letter (“AL”) to submit the program budget request and marketing, education and outreach (“ME&O”) plan for the Disadvantaged Communities Green Tariff (“DAC-GT”) and Community Solar Green Tariff (“CS-GT”) programs for the program year (“PY”) 2024.

TIER DESIGNATION
This AL has a Tier 2 designation pursuant to OP 3 of Resolution E-5125.

EFFECTIVE DATE
Pursuant to G.O. 96-B, MCE requests that this Tier 2 AL become effective on May 3, 2023, which is 30 calendar days from the date of this filing.

BACKGROUND
On June 21, 2018, the California Public Utilities Commission (“Commission” or “CPUC”) approved D.18-06-027, adopting two new community solar programs to promote the use of renewable generation among residential customers in disadvantaged communities (“DACs”),3 as 1 OP 2 and 4 of Resolution E-4999 specifically directed Pacific Gas and Electric Company, Southern California Edison and San Diego Gas & Electric Company to submit annual program budget estimates and ME&O plans to the Commission by February 1 of each year. MCE’s implementation Advice Letter, MCE AL 42-E/E-A/E-B was approved in Resolution E-5124, which brought MCE under the same program rules and reporting structure applicable to the IOUs. 2 OP 3 of Resolution E-5125 directed that DAC-GT and CS-GT Annual Budget Advice Letters are to be submitted as Tier 2 ALs to allow for additional review and oversight. 3 DACs are defined under Resolution E-5212 as communities that are identified in version 3.0 or any subsequent version of CalEnviroScreen as among the top 25 percent of census tracts statewide, plus the MCE Advice Letter 69-E
2 directed by the California Legislature in Assembly Bill (“AB”) 327 (Perea), Stats. 2013, ch 611.

The DAC-GT and the CS-GT programs offer 100% solar energy to eligible customers and provide a 20% discount on the electric portion of the utility bill.

D.18-06-027 allows Community Choice Aggregators (“CCAs”) to develop their own DAC-GT and CS-GT programs, and states that CCAs that elect to offer DAC-GT and CS-GT must abide by all rules and requirements adopted in that decision.4
Pursuant to OP 17 of D.18-06-027, MCE filed
its Implementation AL (MCE AL 42-E) on May 7, 2020. The Commission approved AL 42-E in Resolution E-5124, issued April 15, 2021.

Resolution E-4999 from May 2019 approved the investor-owned utilities’ (“IOUs”) implementation ALs for the DAC-GT and CS-GT programs and established the budgeting procedures and timelines for the programs. The Resolution sets the deadline for submitting annual DAC-GT and CS-GT program budget requests and ME&O plans for the upcoming PY by February 1st of each year.5 On January 24, 2023, MCE, as a part of the Joint CCAs, requested a two-month extension of the budget AL until April 3, 2023. On February 1, 2023, the Joint CCAs’ extension request was granted. Resolution E-4999 also provides details regarding the budget submission requirements and process. Furthermore, the Resolution specifies that Program Administrators must reconcile prior year budget forecasts and expenditures in their annual budget requests.6 Per D.18-06-027, the budget requirements outlined in Resolution E-4999 apply to participating CCAs as well. The submission and approval of this budget AL is the prerequisite of having the DAC-GT and CS-GT budgets included in the IOUs’ Energy Resource Recovery Account (“ERRA”) Forecast in June each year. The ERRA Forecast in turn enables cost recovery under the programs. Therefore, MCE is submitting this cover letter to ensure timely cost recovery for its programs.

PURPOSE
MCE hereby submits the budget request for PY 2024 for the DAC-GT and CS-GT programs. Per Resolution E-4999, the budget request includes both the budget reconciliation for the previous PY (i.e., PY 2022) and the budget forecast for the upcoming PY (i.e., PY 2024). Additionally, MCE includes two corrections for inadvertent errors in last year’s budget AL (MCE AL 58-E). In summary, MCE requests a total budget of $809,170 for the DAC-GT and CS-GT programs for PY 2024. Additional details can be found in Appendix A.

Once the Commission approves MCE’s budget request, PG&E will be responsible for including the total budget request for MCE’s DAC-GT and CS-GT programs in the 2024 ERRA Forecast census tracts in the highest five percent of CalEnviroScreen’s Pollution Burden that do not have an overall CalEnviroScreen score because of unreliable socioeconomic or health data. Resolution E-5212 also expands program eligibility to include California Indian Country. 4 D.18-06-027, p. 104, OP 17.
5 Resolution E-4999, OP 2.
6 Resolution E-4999, OP 4.

MCE Advice Letter 69-E
3 filing, due on May 15th of 2023.7 Once PG&E receives approval of its ERRA Forecast from the Commission, PG&E will set aside the requested MCE budget in a sub-account of its DAC-GT and CS-GT balancing accounts. PG&E will then transfer program funds to MCE as determined in Resolution E-5124.8
In addition to the budget request, MCE submits its updated ME&O plan for PY 2024 as Appendix B.

CONCLUSION
MCE respectfully requests the Commission approve the budgets proposed herein and direct PG&E to transfer funds sufficient to meet MCE’s approved annual budgets per the funding mechanisms set forth in Resolution E-5124. MCE also request approval of its ME&O plan for 2024.

NOTICE
A copy of this AL is being served on the official Commission service lists for Rulemaking R.14- 07-002 and Application A.22-05-022.

For changes to this service list, please contact the Commission’s Process Office at (415) 703-2021 or by electronic mail at [email protected].

PROTESTS
Anyone wishing to protest this advice letter filing may do so by letter via U.S. Mail, facsimile, or electronically, any of which must be received no later than 20 days after the date of this advice filing. Protests must be submitted to:

CPUC, Energy Division
Attention: Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
Email: [email protected]
In addition, protests and all other correspondence regarding this advice letter shall be sent electronically to the attention of:

Amulya Yerrapotu
Policy Associate
7 D.22-01-023, p. 28, OP 3. Modifies the due date for PG&E to file this annual Application to May 15, 2023.

At its January 27, 2021 voting meeting, the Commission adopted a PD that, among other things, sets the ERRA forecast filing due date at May 15 of each year. As of the date of preparation for this AL, that decision had not yet been assigned a Decision number. 8 Resolution E-5124, p. 10.

MCE Advice Letter 69-E
4 Marin Clean Energy
1125 Tamalpais Ave
San Rafael, CA 94901
Email: [email protected]
There are no restrictions on who may file a protest, but the protest shall set forth specifically the grounds upon which it is based and shall be submitted expeditiously.

CORRESPONDENCE
For questions, please contact Amulya Yerrapotu at (415) 464-6664 or by electronic mail at [email protected].
/s/ Amulya Yerrapotu
Amulya Yerrapotu
Policy Associate

MARIN CLEAN ENERGY
1125 Tamalpais Avenue
San Rafael, CA 94901
Telephone: (415) 464-6664
Email: [email protected]
Appendices
Appendix A: PY 2024 Budget Request
Appendix B: PY 2024 ME&O Plan
cc: Service List for R.14-07-002 and A.22-05-022
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Budget Forecast for the Disadvantaged Communities Green Tariff and Community Solar Green Tariff Programs for
Program Year 2024
Proposed by Marin Clean Energy
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TABLE OF CONTENTS

1. BACKGROUND 3

2. BUDGET FORECAST FOR PY 2024 4

3. BUDGET CAPS 5

4. BUDGET RECONCILIATION FOR PY 2022 7

5. CORRECTION OF 2021 ACTUAL COSTS 9

6. 2024 BUDGET REQUEST 9

7. PROGRAM CAPACITY AND ENROLLMENT NUMBERS 9

TABLE OF FIGURES
Table 1: MCE Budget Forecast for PY 2024 4
Table 2: MCE Budget Reconciliation for PY 2022 8
Table 3: MCE Budget Request for PY 2024 9
Table 4: Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2022 9 Table 5: Forecasted Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2024 9
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1. BACKGROUND
MCE is a program administrator (PA) of the Disadvantaged Communities (DAC) Green Tariff (DAC-GT) and Community Solar Green Tariff (CS-GT) programs. Per Resolution E-4999, annual program budgets must be presented by program and include the following budget line items:1

1. Generation cost delta, if any;2

2. 20 percent bill discount for participating customers;

3. Program administration costs: 3
a. Program management;
b. Information technology (IT);
c. Billing operations;
d. Regulatory compliance;
e. Procurement;

4. Marketing, education and outreach (ME&O) costs:
a. Labor costs;
b. Outreach and material costs;
c. Local CBO/ sponsor costs (for CS-GT only).

In this program budget, MCE includes both the budget reconciliation for the previous program year (PY) (i.e., PY 2022) and the budget forecast for the upcoming PY (i.e., PY 2024).

Additionally, MCE includes a correction for an inadvertent error in calculating the actual program costs in last year’s budget advice letter (AL) (MCE AL 58-E).

In addition to budget reconciliation and forecast, annual program budget submissions must also include details on program capacity and customer enrollment numbers for both programs. More specifically, MCE reports on:

1. Existing solar generation capacity at previous PY’s close (i.e., December 31, 2022);

2. Forecasted solar generation capacity under contract for procurement in the upcoming PY;

3. Customers served at previous PY’s close (i.e., December 31, 2022); and

4. Forecasted customer enrollment for the upcoming PY.
1 A detailed description of each budget line item can be found in MCE’s Implementation Plan, submitted in Appendix A to MCE Advice Letter 42-E filed on May 7, 2020. 2 Resolution E-4999 establishes that above market generation costs should include net renewable resource costs in excess of the otherwise applicable class average generation rate that will be used to calculate the customers’ bills. In conversations with the CPUC’s Energy Division after the release of the Resolution, it was clarified that this budget line item is intended to cover both a potential higher, as well as lower, cost of the DAC-GT/ CS-GT resources than the otherwise applicable class average generation rate. Hence, the term is updated to state the “Delta of generation costs between the DAC-GT/ CS-GT resources and the otherwise applicable class average generation rate.” 3 Resolution E-5124 established that PG&E can charge “CCA Integration Costs” to the programs; i.e. costs that incur to PG&E to enable CCAs to administer the programs (e.g., billing support functions). To date, CCAs have been including CCA integration costs on their budget ALs. On March 2, 2023, PG&E submitted Advice Letter 6872-E requesting that the CPUC approve a tariff modification to allow PG&E to record these CCA integration costs directly to PG&E’s subaccount, instead of the CCAs seeking cost recovery. Therefore, MCE does not include the CCA integration cost in its 2024 budget forecast. However, MCE still includes the CCA integration cost in the calculation of its administration cost cap, per Resolution E-5124.

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Finally, MCE will submit the following workpapers to the California Public Utilities Commission’s (CPUC or Commission) Energy Division staff directly:

1. Calculation of the generation cost delta;

2. Calculation of the 20% bill discount to participating customers.

2. BUDGET FORECAST FOR PY 2024
For PY 2024, MCE forecasts a total budget of $1,387,822 for the DAC-GT and CS-GT programs.

A detailed budget forecast for each program by budget line item can be found in the table below.

Table 1: MCE Budget Forecast for PY 2024
MCE provides a brief description of each of the budget line items below.

Generation Cost Delta
To date, MCE has been using interim solar generation resources to support the DAC-GT program while it is procuring a dedicated solar facility for the program. On June 20, 2022, the Commission approved MCE’s request to approve its dedicated DAC-GT power purchase agreement (PPA).4 MCE subsequently executed a contract with the dedicated solar generation facility that is expected to come online in late 2023 or early 2024. As such, the DAC-GT generation cost delta budget forecast for 2024 is based on the PPA price of the dedicated resource, compared to the costs of serving customers under MCE’s residential base tariff, the “Light Green” tariff. 4 See Disposition of MCE AL 63-E, MCE Disadvantaged Communities Green Tariff Program 2022 Power Purchase Agreement Approval.

Tab Category DAC-GT CS-GT
1 Generation Cost Delta $ 131,949 $ -
2 20% Bill Discount $ 963,285 $ -
Program Administration
3a Program Management $ 35,964 $ 19,980
3b Information Technology $ 11,840 $ 3,700
3c Billing Operations $ 97,430 $ 9,620
3d Regulatory Compliance $ 11,750 $ 11,750
3e Procurement $ 27,710 $ 25,876
Subtotal Program Administration $ 184,694 $ 70,926
Marketing, Education & Outreach
4a Labor Costs $ 5,772 $ 7,696
4b Outreach and Material Costs $ 20,500 $ 3,000
4c Local CBO/ Sponsor Costs $ - $ -
Subtotal ME&O $ 26,272 $ 10,696
Total $ 1,306,200 $ 81,622 $ 1,387,822
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MCE did not receive any bids for CS-GT projects in its 2022 solicitation and does not expect to have a generation resource online in 2024 for the CS-GT program. Hence, MCE does not forecast any generation cost delta for 2024 for the CS-GT program. 20 Percent Bill Discount
As set forth in Resolution E-5124, MCE calculates the 20% bill discount on both the generation and transmission and distribution (T&D) portion of the electric bill for the customers participating in its programs. The bill discount is then fully included on the generation portion of customer bills, i.e., the discount reduces the electric generation costs of a customer’s bill only.5 MCE then recovers these program costs via this budget AL filing.

In PY 2024, MCE only expects to have customers enrolled in the DAC-GT program. As described above, MCE has not been successful to date to procure a solar generation facility for the CS-GT program. The PY 2024 forecast for the 20 percent bill discount is based on the actual average monthly bill discount provided to participating customers in 2022, with a 25% increase to account for forecasted increases in electricity rates.

Program Administration Costs
Program management includes program development, management, budgeting, and reporting. IT costs include the costs to develop program tools and updating existing systems to accommodate program enrollment and billing. Billing operations cover costs for ongoing billing operations and customer support, including the costs of MCE’s third-party billing provider. Regulatory covers costs for regulatory compliance and related program filings with the Commission. Procurement covers the costs to develop and manage the solicitations for solar resources under the program, ongoing contract management, as well as annual renewable energy credit (REC) retirement and compliance functions.

Marketing, Education and Outreach (ME&O)
ME&O budgets are split in three categories – (1) MCE labor costs; (2) MCE direct costs for outreach and material; and (3) funds provided to the local CBOs who function as the sponsor for the CS-GT program.

3. BUDGET CAPS
Resolution E-4999 establishes a cap of 10% of the total budget for program administration costs and a cap of 4% of the total budget for ME&O costs, to apply beginning with each administrator’s third program year.6 Subsequently, in recognition that these programs may exceed the established caps because of their relatively small size, the time it takes to launch, and the management-intensive program design of CS-GT, and other factors, the Commission permitted PAs whose budgets exceed the established caps to submit a rationale supporting the exceedance in their Annual Budget Advice Letters (ABAL).7 The ABAL was elevated from Tier 1 to Tier 2 to allow 5 Resolution E-5124, p. 12.
6 Resolution E-4999, p. 27.
7 Resolution E-5125, p. 7.

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for additional review of this and other ABAL components.8 The 2024 budget forecast summarized above in Table 1 results in program administration budgets of 14% for DAC-GT and 87% for CS-GT, and ME&O budgets of 2% for DAC-GT and 13% for CS-GT. As such, MCE requests an adjustment to the program administration budget cap for both DAC-GT and CS-GT, and to the ME&O budget cap for CS-GT, for PY 2024. The factors contributing to these forecasts are described below.
2024 DAC-GT Program Administration Budget Forecast
Two main factors contribute to MCE exceeding the cost cap on administrative costs for the DAC-GT program. First and foremost, MCE continues to calculate and provide the bill discount to participating customers in a manual fashion, instead of an automated fashion as implemented under the IOUs’ programs. Manual billing procedures are costly - they account for 52% of MCE’s total administrative costs for the DAC-GT program. Without these manual billing costs, MCE would meet the cost cap with admin costs of 7% of the total DAC-GT budget. MCE has been advocating with the Commission for an automated billing solution to mitigate these annual billing costs.9 Until such an automated billing solution is implemented, the CCAs’ administrative costs must be viewed differently than the IOU’s administrative costs. The IOU PAs were able to recover the costs to implement an automated billing solution in the first two years of program operation, i.e., when the cost cap did not apply to the programs yet.10 Instead of incurring high IT and billing operations costs in the first two years of program implementation, the Joint CCAs will incur annual high billing costs throughout the duration of the program due to the manual nature of the billing solution for participating CCA customers.

A second factor contributing to MCE’s relatively higher admin costs compared to previous years is the fact that MCE anticipates serving customers with a dedicated DAC-GT resource beginning in late 2023 or early 2024. This new resource is substantially less expensive than the interim resource currently supplying participating customers. As a result, the generation cost differential is reduced, making program administration costs a comparatively larger share of overall program expenses in 2024. Furthermore, as this new resource comes online, MCE anticipates additional procurement and program administration staff time to facilitate the integration of the new resource into the program. MCE anticipates that these will be one-time costs associated with the transition.

These factors, in conjunction with the relatively small capacity allocation assigned to MCE,11 cause MCE’s program administration budget forecast to exceed 10% of its total DAC-GT budget. 2024 CS-GT Program Administration Budget Forecast
As noted above, MCE has not yet received any qualifying bids for CS-GT projects, and therefore does not include any generation cost delta or bill discount forecasts for CS-GT in its PY 2024 8 Id.
9 A.22-05-022, Public Prepared Testimony on Behalf of the Joint Community Choice Aggregators and City and County of San Francisco, Joint Community Choice Aggregators and City and County of San Francisco, 1/20/23 10 Per PG&E AL 5750-E, PG&E recovered $1,161,165 million for IT costs in 2019 11 Per Resolution E-5124, MCE’s capacity allocation for DAC-GT is 4.646 MW.

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forecast. However, program administration costs are still being incurred, as MCE works to identify qualifying projects, create and refine administrative processes, engage in regulatory and compliance activities, and prepare to launch its program. These program costs therefore represent a large portion of the budget, with few other budget components to be compared against.

As discussed in Resolution E-5125, CS-GT may be particularly difficult to hold to a 10% program administration cost cap because of its management-intensive program design, relatively small capacity allocations,12 and extended procurement and customer enrollment time frames. MCE has experienced some of these challenges to date in its attempts to identify potential community sponsors and project sites that meet CS-GT criteria. MCE includes in its forecast sufficient staff time to properly support CS-GT rollout, including procurement and customer enrollment, in anticipation of receiving successful project bids in its next solicitation. 2024 CS-GT ME&O Forecast
As noted above, to date MCE has no CS-GT generation cost delta or bill discount forecasts to accompany the ME&O costs. As detailed in the accompanying ME&O plan for 2024 (Appendix B), MCE anticipates incurring ME&O costs in 2024 as it will continue to work to identify qualifying projects for the CS-GT program. These factors contribute to a CS-GT ME&O forecast in excess of the established 4% cap.

4. BUDGET RECONCILIATION FOR PY 2022
MCE submitted a budget forecast for PY 2022 as a part of its 2022 Budget Request and Marketing, Education, and Outreach Plan in AL 47-E on February 1, 2021. The table below shows the forecasted and actual costs for PY 2022 per budget line item, as well as the true-up amount that will be carried forward to future program years.
12 Per Resolution E-5124, MCE’s capacity allocation for CS-GT is 1.2825 MW.

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Table 2: MCE Budget Reconciliation for PY 2022
Tab Category
Forecast Actual True-up Forecast Actual True-up
1 Generation Cost Delta $ 1,220,491 $ 843,492 $ 377,000 $ - $ - $ - 2 20% Bill Discount $ 488,549 $ 770,628 $ (282,079) $ - $ - $ - Program Administration
3a Program Management $ 101,250 $ 14,424 $ 86,826 $ 136,950 $ 3,778 $ 133,172 3b Information Technology $ 40,604 $ 7,212 $ 33,392 $ 22,007 $ 1,889 $ 20,118 3c Billing Operations $ 37,342 $ 66,762 $ (29,420) $ 10,308 $ 1,889 $ 8,419 3d Regulatory Compliance $ 14,280 $ 6,911 $ 7,369 $ 14,280 $ 4,402 $ 9,878 3e Procurement $ 18,235 $ 34,280 $ (16,045) $ 31,682 $ 6,332 $ 25,350 3f CCA Integration Costs $ 31,014 $ 3,941 $ 27,074 $ 31,014 $ - $ 31,014 Subtotal Program Administration $ 242,725 $ 133,529 $ 109,197 $ 246,241 $ 18,291 $ 227,950 Marketing, Education & Outreach
4a Labor Costs $ 18,445 $ 1,002 $ 17,443 $ 54,740 $ 258 $ 54,482 4b Outreach and Material Costs $ 2,800 $ 13,410 $ (10,610) $ 53,500 $ - $ 53,500 4c Local CBO/ Sponsor Costs $ - $ - $ - $ 25,000 $ - $ 25,000 Subtotal ME&O $ 21,245 $ 14,412 $ 6,833 $ 133,240 $ 258 $ 132,982 Total $ 1,973,011 $ 1,762,060 $ 210,950 $ 379,481 $ 18,548 $ 360,932

DAC-GT CS-GT
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5. CORRECTION OF 2021 ACTUAL COSTS
While preparing its 2024 Budget Advice Letter, MCE noticed and corrected an inadvertent error in its calculation of the 2021 Actual Generation Cost Delta for the DAC-GT program. MCE AL 58-E incorrectly reported the 2021 Actual Generation Cost Delta as $151,027. After correcting the error, MCE’s 2021 Actual Generation Cost Delta is $145,521. The difference in cost delta amounts to $5,506.

MCE also noticed and corrected an inadvertent error in its 2021 budget reconciliation. In MCE AL 58-E, the CS-GT forecasted CCA integration costs of $1,263 are incorrectly excluded from the true-up, and therefore the reconciliation total.

MCE submits these corrections as a separate line item in its 2024 Budget Request in Section 6.

6. 2024 BUDGET REQUEST
Based on the budget forecast for PY 2024 presented in Section 2, the budget reconciliation for PY 2022 presented in section 4, and the correction for PY 2021 presented in section 5, MCE is requesting a total budget of $809,170 for the DAC-GT and CS-GT programs in this budget AL.

Table 3: MCE Budget Request for PY 2024

7. PROGRAM CAPACITY AND ENROLLMENT NUMBERS
MCE reports existing program capacity and customer enrollment numbers as of December 31, 2022 in Table 4 below. In PY 2022, enrolled customers were served with an interim solar resource, as discussed above.

Table 4: Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2022 Category DAC-GT CS-GT
Existing program capacity (MW) 4.646 0
Participating customers (#) 3,265 0
In Table 5, MCE reports forecasted capacity and customer enrollment for PY 2024. As noted above, MCE is currently in contract negotiations for a dedicated solar project to support DAC-GT, and estimates that the new project will come online in late 2023 or early 2024. However, having DAC-GT CS-GT Total
Budget Carry-over from PY 2022 $ (210,950) $ (360,932) $ (571,883) Budget Forecast for PY 2024 $ 1,306,200 $ 81,622 $ 1,387,822 Advice Letter 58-E Corrections $ (5,506) $ (1,263) $ (6,769) TOTAL $ 1,089,744 $ (280,573) $ 809,170
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received no qualifying bids for CS-GT projects in 2022, MCE does not anticipate launching a CS-GT program and enrolling customers in 2024. Therefore, MCE does not have any forecasted program capacity under contract for 2024.

Table 5: Forecasted Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2024
Category DAC-GT CS-GT
Estimated capacity to be procured (MW) 4.646 0
Estimated customer enrollment (#) 3,265 0
B-1
Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff and Community Solar Green Tariff Programs for Program Year 2024
Proposed by Marin Clean Energy
B-2

TABLE OF CONTENTS

1. PURPOSE AND GOALS 1

2. GUIDING PRINCIPLES 1

3. TARGET AUDIENCE 2

4. ME&O TACTICS AND STRATEGIES 4

4.1. Communications and Media Content 4

4.2. Community Outreach 4

4.2.1. Grassroots Outreach 4

4.2.2. Partnerships with Community Based Organizations 4

4.3. Program Leveraging 5

5. METRICS TRACKING 6

TABLE OF FIGURES
Figure 1. Qualifying Neighborhoods in MCE Service Area for DAC-GT Auto-enrollment 3 Figure 2. Qualifying Neighborhoods in MCE Service Area for GS-GT 3 Figure 3. MCE ME&O Tactics and Strategies 3
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1. PURPOSE AND GOALS
MCE will develop and implement a targeted customer marketing, education, and outreach (ME&O) campaign under the Disadvantaged Communities Green Tariff (DAC-GT) and Community Solar Green Tariff (CS-GT) programs to ensure potential customers in disadvantaged communities (DACs) are aware of the opportunity to benefit from the programs.

MCE will develop and implement separate targeted customer marketing, education, and outreach (ME&O) campaigns for the DAC-GT and CS-GT programs due to the differing enrollment processes of the two programs. Eligible customers for DAC-GT will be identified and automatically enrolled in the program by MCE. Hence, no customer recruitment for program participation is required. Eligible customers for CS-GT will not be automatically enrolled in the program; instead, interested customers will be required to opt their accounts into the program by completing an enrollment form. For both ME&O campaigns, MCE aims to achieve meaningful and diverse customer engagement through a culturally-competent, multilingual approach.

MCE’s ME&O strategy for the DAC-GT program has three main goals:

1. Notify DAC-GT customers that their account has been automatically enrolled in the program;

2. Provide information (i.e., FAQs) about the program; and

3. Notify DAC-GT customers if they no longer meet eligibility criteria for the program (i.e., moved, installed solar, or no longer enrolled in CARE or FERA) and provide instructions on how to continue their program participation (if applicable).

MCE’s ME&O strategy for the CS-GT program also has three main goals:

1. Enroll eligible customers in the CS-GT program (expected in 2025);

2. Increase awareness and enrollment in California Alternate Rates for Energy (CARE) and Family Electric Rate Assistance (FERA) programs; and

3. Address barriers to program participation and leverage best practices to ensure that outreach to DAC and historically impacted customers is accessible and equitable.

2. GUIDING PRINCIPLES
MCE is committed to developing diverse and culturally appropriate communication strategies to ensure that stakeholders can participate in decisions and actions that impact their communities. As such, MCE commits to the following guiding principles throughout the ME&O engagement process for the DAC-GT and CS-GT programs. MCE aims to:
● Achieve diverse and meaningful engagement that reflects the demographics of DAC communities to ensure equitable outreach across race, income and age barriers; B-4
● Maintain transparency and accessibility by bringing information directly to customers’ neighborhood, community, or interest space to better engage them in the process; and ● Build a collaborative process with community partners to ensure barriers and benefits to participation are considered in the ME&O activities to the maximum extent possible.

3. TARGET AUDIENCE
For the DAC-GT program, in 2021 MCE automatically enrolled eligible customers that live in one of the top 10% of DAC census tracts statewide that are in MCE’s service area, as defined by CalEnviroScreen 4.0. Priority was given to customers who made an effort to pay, as defined by at least 4 full or partial payments in the last 8 months (category 1). If program capacity remains unsubscribed after enrolling these customers, MCE will enroll additional customers in the following order:
● Customers who have made at least 3 full or partial payments in the past 8 months (category 2)
● Customers who have made at least 2 full or partial payments in the past 8 months (category 3)1
After its initial enrollment for the DAC-GT program, which prioritized customers in arrears who have made payments, there was additional capacity for the program. MCE then enrolled customers enrolled in CARE or FERA in 90th percentile DACs. As capacity becomes available, MCE continues to enroll all CARE/FERA customers living in 90th percentile DACs, with priority given to those who have been on the waitlist for the greatest amount of time.

If there is insufficient program capacity to enroll all customers in a category under the DAC-GT program, customers from the eligible category will be randomly selected for program enrollment.

MCE will monitor program attrition on a monthly basis and enroll additional customers from the waitlist as appropriate.

Figure 1 shows the list of eligible census tracts for DAC-GT auto-enrollment.

Figure 1. Qualifying Neighborhoods in MCE Service Area for DAC-GT Auto-enrollment 90% CalEnviroScreen Score
Census
Tract
California
County ZIP
Nearby City
(to help approximate
location only)
6013379000 Contra Costa 94804 Richmond
6013312000 Contra Costa 94565 Pittsburg
6013365002 Contra Costa 94801 Richmond
6013377000 Contra Costa 94801 Richmond
1 MCE has the capacity to serve approximately 3,265 customers under the DAC-GT program, based on an allocated program capacity of 4.646 MW
B-5
For the CS-GT program, the target audience for the ME&O strategy are existing and eligible CARE/FERA customers living in top 25% DAC census tracts as defined by CalEnviroScreen 3.0 and any subsequent versions. Figure 2 shows the list of eligible census tracts for CS-GT in MCE’s service area.

Figure 2. Qualifying Neighborhoods in MCE Service Area for CS-GT under CalEnviroScreen 3.0 Census Tract County Zip
Nearby City (to help
approximate
location only)
6013379000 Contra Costa 94804 Richmond
6013312000 Contra Costa 94565 Pittsburg
6013365002 Contra Costa 94801 Richmond
6013377000 Contra Costa 94801 Richmond
6013382000 Contra Costa 94804 Richmond
6013368002 Contra Costa 94806 San Pablo
6013376000 Contra Costa 94801 Richmond
6013310000 Contra Costa 94565 Pittsburg
6013311000 Contra Costa 94565 Pittsburg
6095250701 Solano 94590 Vallejo
6013305000 Contra Costa 94509 Antioch
6013380000 Contra Costa 94804 Richmond
6013375000 Contra Costa 94801 Richmond
6095250801 Solano 94592 Vallejo
6013366002 Contra Costa 94806 San Pablo
6095250900 Solano 94590 Vallejo
6013368001 Contra Costa 94806 San Pablo
6013358000 Contra Costa 94572 Rodeo
6013381000 Contra Costa 94804 Richmond
6013314103 Contra Costa 94565 Pittsburg
6013320001 Contra Costa 94553 Martinez
6013314104 Contra Costa 94565 Pittsburg
6013313102 Contra Costa 94565 Pittsburg
6013309000 Contra Costa 94565 Pittsburg
6013313101 Contra Costa 94565 Pittsburg
B-6
6013364002 Contra Costa 94806 San Pablo
6013392200 Contra Costa 94806 San Pablo
6095251802 Solano 94589 Vallejo
6013302005 Contra Costa 94561 Oakley
6095251901 Solano 94589 Vallejo
Figure 3. Qualifying Neighborhoods in MCE Service Area for CS-GT under CalEnviroScreen 4.0 Census Tract County Zip
Nearby City (to help
approximate
location only)
6095250701 Solano 94590 Vallejo
6013365002 Contra Costa 94801 Richmond
6013377000 Contra Costa 94801 Richmond
6013376000 Contra Costa 94801 Richmond
6013379000 Contra Costa 94804 Richmond
6013382000 Contra Costa 94804 Richmond
6095250900 Solano 94590 Vallejo
6013305000 Contra Costa 94509 Antioch
6095250801 Solano 94592 Vallejo
6013312000 Contra Costa 94565 Pittsburg
6013375000 Contra Costa 94801 Richmond
6013311000 Contra Costa 94565 Pittsburg
6095251802 Solano 94589 Vallejo
6013366002 Contra Costa 94806 San Pablo
6013310000 Contra Costa 94565 Pittsburg
6013381000 Contra Costa 94804 Richmond
6013392200 Contra Costa 94806 San Pablo
6013358000 Contra Costa 94572 Rodeo
6095252402 Solano 94534 Fairfield
6013314104 Contra Costa 94565 Pittsburg
6013368001 Contra Costa 94806 San Pablo
6013327000 Contra Costa 94520 Concord
B-7
6013309000 Contra Costa 94565 Pittsburg
6095253500 Solano 94571 Rio Vista
6095251902 Solano 94589 Vallejo
6013368002 Contra Costa 94806 San Pablo
6013369001 Contra Costa 94806 San Pablo
6095251901 Solano 94589 Vallejo
6095251000 Solano 94590 Vallejo
6013307102 Contra Costa 94509 Antioch
6013314200 Contra Costa 94565 Pittsburg
6013306003 Contra Costa 94509 Antioch
6013380000 Contra Costa 94804 Richmond
6095251803 Solano 94589 Vallejo
6013336201 Contra Costa 94520 Concord
6095251600 Solano 94590 Vallejo
6013314103 Contra Costa 94565 Pittsburg
6013314102 Contra Costa 94565 Pittsburg
6013306002 Contra Costa 94509 Antioch
B-8

4. ME&O TACTICS AND STRATEGIES

4.1. Communications and Media Content
MCE will continue to use the communications and media content originally developed to promote DAC-GT, including mailers and web. Similar materials will be developed in preparation for the CS-GT launch, currently expected in 2025. At launch, MCE will promote CS-GT through digital, social media, and print advertisements; and customer emails and mailers in multiple languages to encourage program enrollment.

4.2. Community Outreach
To meet its ME&O goals, MCE will develop an outreach and engagement strategy leveraging the key community outreach tactics summarized below. The community outreach strategy will include a multilingual and culturally competent approach to engagement and consider the specific needs of eligible communities in MCE’s service area. CS-GT outreach will be informed by data (including census tracts, the 4013 customer data file from PG&E, etc.) in order to identify customers who are most likely to enroll in the program.

4.2.1. Grassroots Outreach
MCE will conduct grassroots outreach to engage directly with community members at community events. MCE already regularly attends and sponsors many community events throughout its service area, including neighborhood festivals, farmers markets, holiday celebrations, and special events. Under the community outreach strategy for the CS-GT program, MCE will focus on expanding the breadth of events attended in DAC neighborhoods.

MCE will utilize the expertise of community leaders to identify impactful events, and will offer workshops and webinars as appropriate. As community events and workshops are held, MCE will closely track the diversity in race, age and income of participants, to ensure that participation reflects census distribution demographics of the DAC communities. MCE will ensure that all MCE-hosted meetings and events, either virtual or in-person, are ADA accessible. MCE will also endeavor to ensure that all in-person events are accessible by public transportation.

At this time, it is difficult to predict whether COVID-19 and associated public health precautions will continue to impact community engagement in 2024. Where required, recommended, or appropriate, MCE will conduct virtual workshops and webinars, and make use of digital toolkits, to ensure community members can safely learn about and enroll in CS-GT. MCE will continue to participate in in-person community outreach events as long as it is safe to do so.

4.2.2. Partnerships with Community Based Organizations
Partnering with Community Based Organizations (CBOs) is a critical facet of MCE’s ME&O plan.

CBOs have intimate knowledge of the local communities they serve and will serve as valuable resources for how best to conduct outreach that makes sense for members of their communities. In engaging with CBO partners, MCE seeks to establish open dialogue, build awareness and understanding among community members, identify community-specific issues, and develop B-9
methods for disseminating relevant information. For example, CBOs can help coordinate program-specific workshops to disseminate program information to their constituencies. MCE will provide funding for CBOs to conduct outreach for the CS-GT program.

Additionally, many other local City departments already conduct outreach in the same communities in which MCE will conduct CS-GT outreach. MCE will investigate and pursue opportunities to collaborate as appropriate.

4.3. Program Leveraging
California offers a plethora of clean energy, energy efficiency, and energy storage programs, with several of them targeting income-qualified customers or customers in DACs. Complementing the state’s programs, MCE has also developed a wide range of in-house program offerings, many of which also focus on low-income customers and/or customers in DACs. MCE’s Any Open Door model provides “behind-the-scenes” coordination with various programs and funding sources in order to provide MCE’s customers with the comprehensive, streamlined “one-stop-shop” guidance they need to navigate and enroll in these different offerings, maximizing the benefit to the customers while interweaving the value of all leveraged programs.

Under the DAC-GT/CS-GT ME&O plan, MCE will leverage its relationships and interactions with customers through existing programs to inform, educate and encourage program participation through its Any Open Door model. For example, MCE will leverage the following programs for joint outreach efforts: MCE’s Energy Storage Program, MCE’s Low-Income Families and Tenants (LIFT) pilot that offers electrification and energy efficiency upgrades to low-income multifamily properties, MCE’s electric vehicle rebate and grant programs for low-income customers, and debt relief programs like the Arrearage Management Program (AMP) and the Low Income Home Energy Assistance Program (LIHEAP).

Additionally, MCE will pursue program leveraging with relevant programs administered by partners, other local CBOs, and local government entities.

B-10
Figure 3. MCE ME&O Tactics and Strategies
*Component of CS-GT ME&O only. Due to auto enrollment provisions and to limit customer confusion about program eligibility, these tactics will not be used for the DAC-GT program.

5. METRICS TRACKING
Because MCE is using multiple tactics for ME&O, a variety of metrics will be used to evaluate the effectiveness of each effort. Our primary measure of effectiveness is the number of customers reached, which can be measured by:
● DAC-GT
o Number of customers enrolled based on auto enrollment criteria; and o Number of customers opting to cancel program participation. ● CS-GT2
o Total number of enrollees;
o Total CARE and FERA enrollment achieved through CS-GT outreach; o Total number of customers reached;
o Diversity in race, age and income of event participants, with participation that reflects census distribution demographics of MCE’s DAC communities; o Direct mail and email - email click-through and open rates; 2 MCE anticipates CS-GT will launch in 2025. To the extent that marketing efforts begin in late 2024 in preparation for launch, MCE will design its ME&O efforts to align with these metrics.

Communications and Media Content
Social Media*
MCE
Website
Flyers/ fact
sheets*
Print and digital
advertisement*
Di
Grassroots Outreach
Community
Events
Workshops and
Webinars
Collaboration with Community
Leaders
CBO Partnerships
Joint
outreach
Funding support
Program
Leveraging
MCE Energy Storage
Program(s)
MCE low-income solar
program
MCE LIFT pilot
MCEv

B-11
o Indirect website visits and page views, social media engagement and impressions; and
o Total number of events and distribution of events by neighborhood.

By regularly monitoring these measures, MCE will be able to make changes in its approach or shift the mix of ME&O channels to improve the effectiveness of outreach, if necessary.

Additionally, feedback from CBO partners, surveys, on-the-ground interactions, and message testing could lead MCE to alter its strategy to improve its effectiveness.