Regulatory Packet — MCE Board of Directors, September 19, 2024 (part 1 of 2)

JULY FILINGS
July 1, 2024

VIA ELECTRONIC MAIL
Public Utilities Commission of the State of California
Energy Division
Attention: Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, CA 94102
Advice Letter 15-E
Apple Valley Choice Energy
Advice Letter 9-E
Clean Ener!!V Alliance
Advice Letter 10-E
Desert Community Energy
Advice Letter 78-E
Marin Clean Energy
Advice Letter 23-E
Pico Rivera Innovative
Municipal Enerev
Advice Letter 13-E
Rancho Mirage Energy
Authority
Advice Letter 21-E
San Jacinto Power
Advice Letter 32-E
Silicon Valley Clean Ener2v
Advice Letter 48-E
Ava Community Energy
Advice Letter 27-E
Clean Power Alliance
Advice Letter 6-E
Energy For Palmdale's
Independent Choice
Advice Letter 9-E
Orange County Power
Authority
Advice Letter 19-E
Pioneer Community Energy
Advice Letter 21-E
Redwood Coast Energy
Authority
Advice Letter 35-E
San Jose Clean Energy
Advice Letter 23-E
Sonoma Clean Power
Advice Letter 41-E
Central Coast Community
Enerev
Advice Letter 29-E
CleanPowerSF
Advice Letter 28-E
Lancaster Energy
Advice Letter 34-E
Peninsula Clean Energy
Advice Letter 10-E
Pomona Choice Energy
Advice Letter 20-E
San Diego Community
Power
Advice Letter 6-E
Santa Barbara Clean
Enerev
Advice Letter 18-E
Valley Clean Ener!!V
RE: Joint CCAs' Community Choice Aggregator Financial Monitoring and Reporting Guidelines Tier 2 Advice Letter Submitted to Aid in the Implementation of Ordering Paragraph 7 of Decision 24-04-009
California Community Choice Association (CalCCA) submits this Tier 2 Advice Letter (Advice Letter) on behalf of Apple Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Dese1i Community Energy, Energy For Pahndale's Independent Choice, Lancaster 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, CalCCA I Joint CCAs T2 Advice Letter
July 1, 2024
Page2
San Jose Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy1 (collectively, the Joint CCAs). This Advice Letter is submitted to aid Energy Division staff in the implementation of Ordering Paragraph (Oil) 7 of Decision (D.)24-04-0092 (the Decision) as well as provide clarity to the Joint CCAs on required reporting triggers. The Joint CCAs request the California Public Utilities Commission's (Commission) approval of the CCA Financial Monitoring and Repmting Guidelines document attached to this Advice Letter as Appendix A.

I. TIER DESIGNATION
The Joint CCAs hereby submit this Advice Letter with a Tier 2 designation.

II. EFFECTIVE DATE
This Tier 2 Advice Letter will become effective July 31, 2024, the 30th calendar day after the date submitted.

III. BACKGROUND
The Commission opened the Provider of Last Reso1t (POLR) proceeding, Rulemaking (R.) 21-03-011, on March 18, 2021, to implement Senate Bill (SB) 520 (Hertzberg 2019). SB 520 directed the Commission to develop rnles and regulations for a POLR should a community choice aggregator (CCA) or Energy Service Provider cease load service. SB 520 identified the investor-owned utilities (IOUs) as the initial POLRs and ordered the Commission to ensure cost recove1y, continuity of service and reliability, and continuation of California's clean energy goals.

R.21-03-011 considered, among other things, financial monitoring and repo1ting requirements that would provide the Commission with advance notice of CC As' financial positions that may indicate a potential customer return to the POLR. D.24-04-009 adopted financial monitoring and repo1ting requirements aimed at "promot[ing] greater situational awareness for any CCA that is at risk of defaulting on its procurement obligations, and which may lead to the involuntary return of customers to POLR service."3 D.24-04-009 adopted two tiers of financial monitoring and repo1ting requirements for CCAs. Under the first tier, all CCAs, regar·dless of their financial standing or years of operation, are required to provide the Energy Division with a copy of their most recent audited financial information. The audited financial statement shall be provided once a year, in January or July, whichever comes earlier relative to the availability of the audited financial statement. Under the The Joint CCAs have provided CalCCA with autho1ity to submit this Advice Letter on their behalf. 2 D.24-04-009, Decision Implementing Senate Bill 520 Regarding Standards for Provider of Last Resort, R.21-03-011 (Apr. 18, 2024):
https://docs.cpuc.ca.gov/PublishedDocs/Published/GO00/M529/K986/529986322.PDF. 3 Id. at 73.

CalCCA I Joint CCAs T2 Advice Letter
July 1, 2024

Page 3 ends

second tier, CCAs must report additional financial information if they meet certain conditions indicative of financial strain.

IV. PURPOSE
Following the adoption ofD.24-04-009, CalCCA files this Advice Letter supplementing D.24-04-009 with additional guidance on (1) how and when to evaluate the conditions for two-tier financial reporting, and (2) repo1ted financial info1mation for tier-two reporting. CalCCA files this Tier 2 Advice Letter on behalf of the Joint CCAs to request approval of the CCA Financial Monitoring and Reporting Guidelines document attached to this Advice Letter as Appendix A. CalCCA also provides a description of the Appendix here:
• Section 1 of Appendix A documents the Tier 2 reporting conditions and an explanation of each condition. Unless specified, Tier 2 reporting applies to CCAs that meet any one of the conditions.
• Section 2 of Appendix A documents how and when CCAs must report the occunence of a Tier 2 condition. Depending on the condition, CCAs must repo1t within 10 business days of the occunence or within 10 days of the CCA's acceptance of its financial statement. It also documents its engagement with Energy Division and information that it must repmt to Energy Division upon meeting a Tier 2 condition. • Section 3 discusses when a CCA may cease a previously triggered Tier 2 repmt. • Section 4 documents how a CCA requests confidential treatment of market sensitive information repo1ted to Energy Division.
• Section 5 of Appendix A describes the enforcement mechanism used to ensme that CCAs report to the Energy Division on time in accordance with the deadlines outlined in Section 2.

V. PROTEST
Anyone wishing to protest this Advice Letter may do so only by electronical mail.

Protests must be received no later than 20 days after the date of this Advice Letter. Protests should be submitted to the Commission Energy Division at:

E-mail: [email protected].

In addition, protests and all other conespondence regarding this Advice Letter should also be sent by electronical mail to the attention of:

California Community Choice Association
Attn: Evelyn Kahl
General Counsel and Director of Policy
[email protected]
CalCCA I Joint CCAs T2 Advice Letter
July 1, 2024

Page 4 ends

California Community Choice Association
Attn: Eric Little
Director of Regulato1y Affairs
[email protected]
California Community Choice Association
Attn: Lauren Can
Senior Market Policy Analyst
[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 must be received by the deadline shown above.

VI. NOTICE
In accordance with G.O. 96-B, Section IV, a copy ofthis Advice Letter is being sent by electronic mail to each pa1iy ofrecord in the official service list for R.21-03-01 1. For changes to this se1vice list, please contact the Commission's Process Office at (415) 703-2021, or by electronic mail at Process [email protected].

VII. CORRESPONDENCE
All questions concerning this Advice Letter should be directed to Evelyn Kahl at (510) 980-9459, or by electronic mail at: [email protected].

VIII. CONCLUSION
The Joint CCAs respectfully request that the Commission approve the CCA Financial Monitoring and Repo1t ing Guidelines document attached to this Advice Letter as Appendix A.

Respectfully,

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

Energy Division Ta1iffUnit ([email protected])
Se1vice List: R.21-03-01 1

APPENDIX A
TO

JOINT CCAS' COMMUNITY CHOICE AGGREGATOR FINANCIAL MONITORING AND REPORTING GUIDELINES TIER 2 ADVICE LETTER SUBMITTED TO AID IN THE IMPLEMENTATION OF ORDERING PARAGRAPH 7 OF DECISION 24-04-009

CCA FINANCIAL MONITORING AND REPORTING GUIDELINES

COMMUNITY CHOICE AGGREGATORS (CCA)

FINANCIAL MONITORING AND REPORTING GUIDELINES
UPDATED JULY 1, 2024
Decision (D.) 24-04-009 adopted two tiers of financial monitoring and repo1ting requirements for CCAs. Under the first tier, all CCAs, regardless of their financial standing or years of operation, are required to provide the Energy Division with a copy of their most recent audited financial infom1ation. The audited financial statement shall be provided once a year, in Janua1y or July, whichever comes earlier relative to the availability of the audited financial statement. Under the second tier, CCAs must rep01t additional financial inf01mation if they meet certain conditions indicative of financial strain. This guideline document supplements D.24-04-009 with additional guidance on (1) how and when to evaluate the conditions for tier-two financial rep01ting, and (2) rep01ted financial info1mation for tier-two rep01ting.

1. Conditions that Trigger Tier-Two Financial Reporting Tier 2 rep01ting applies to CCAs that meet any of the following conditions in Table 1:

Table 1: Tier-Two Reporting Conditions
Condition Explanation
The CCA receives a credit rating below BBB- This condition applies only to CCAs who are /Baa3 from S&P & Moody's downgraded from an investment grade rating to a noninvestment grade rating. This
condition does not require all CCAs to obtain
a credit rating.

Days Liquidity on Hand (DLOH) is less than DLOH is defined as a CCA's available 45 days umestricted cash and investments and eligible
unused bank letters of credit, credit
Note: this condition triggers Tier 2 reporting only if the agreements, and capacity under commercial Adjusted DSCR trigger is also met. paper programs, multiplied by 365. This amount shall then be divided by the total of
the last twelve months of the CCA's operating
and maintenance expenses, excluding
depreciation and am01tization.

Adjusted Debt Service Coverage Ratio Adjusted DSCR is defined as: Numerator: For (DSCR) is less than 1. 0 the last twelve months, recuning revenue plus interest income plus withdrawals from a Rate
Note: this condition triggers Tier 2 reporting only if the Stabilization Fund, minus recuning cash DLOH trigger is also met. operating expenses and General Fund
Transfers over the prior twelve-month period
(where recuning revenue and recmTing
expenses exclude special, one-time items, and
annual operating expenses exclude
depreciation and amortization expenses).
1 Denominator: Aggregate debt service over the
prior twelve-month period (i.e., principal,
interest, and fees, as applicable, associated
with the debt).

Cash reserv es for the CCA fall below 5 Cash reserves are defined as cash, cash percent of annual expenses equivalents, short-term investments, and unused credit facilities.

The measme of cash reserves must be directly
tied to the CCA. It should not consider a
city's general fund cash reserves.

Where "annual expenses" are defined as the
last twelve months of the CCA's operating
and maintenance expenses, excluding
depreciation and amortization.

The CCA defaults on one or more This condition is specific to the occunence of procurement contracts required to meet RA an event of default for buyer non-payment requirements due to non-payment after opportunities for disputes and cures have been exhausted as provided within the
contract.

The CCA defaults to its CAISO scheduling NIA
coordinator due to non-payment
The CCA becomes insolvent or files for NIA
bankruptcy, or the CCA has a reasonable
expectation that either event will occur

2. Tier-Two Reporting Requirements
The following conditions must be reported via a confidential letter to the Director of Energy Division within 10 business days of the occunence:
• The CCA receives a credit rating below BBB-/Baa3 from S&P & Moody's; • The CCA defaults on one or more procurement contracts required to meet RA requirements due to non-payment;
• The CCA defaults to its CAISO scheduling coordinator due to non-payment; and • The CCA becomes insolvent or files for bankrnptcy, or the CCA has a reasonable expectation that either event will occur.

The following conditions must be reported via a confidential letter to the Director of Energy Division within 10 business days of the CCA's acceptance of a financial statement: 1 • DLOH is less than 45 days and DSCR is less than 1.0; and CCAs regularly review and update financial statements. Unaudited financial statements should be prepared as soon as practicable and, in any event, within sixty days after the end of each month in which the trigger occmTed. If updated financial information is obtained after such submittal, the CCA will provide that update to the Director of the Energy Division to help inform any prior trigger repo1ting. 2 • Cash reserves for the CCA fall below 5 percent of annual expenses.

Upon meeting any of the Tier 2 repmiing conditions above and submitting the confidential letter to Energy Division, the CCA must meet with Energy Division as requested, up to one meeting per month, and provide the following information:
• Energy and hedging contracts for the next six months with te1m details; • Status of all procurement contracts, in pa1iicular, those at risk of default; • Detailed financial inf mmation as requested by the Commission including, but not limited to, the CCA's most recent financial statements and DLOH; • Plan for financial conection and/or market exit.

3. Graduating from Tier-Two Reporting Requirements
A CCA will graduate from the Tier 2 reporting requirements if it does not meet any Tier 2 triggers (except for the insolvency/bankruptcy condition) for six consecutive months.

4. Confidentiality
If a CCA believes that its letter notifying the Energy Division of a triggered Tier 2 condition, or any of its attendant repmting, is market sensitive, the CCA should follow the regular Commission process for securing confidential treatment.

5. Enforcement
A CCA that fails to submit a letter to the Energy Division by the deadlines outlined in Section 2 will incur a penalty of $1,000 per incident plus $500 per day for the first ten days the filing was late and $1,000 for each day thereafier. Commission Staff and the Commission may take any action provided by law to recover unpaid penalties and ensure compliance with applicable statutes and Commission orders, decisions, mies, directions, demands, or requirements. 3 ADVICE LETTER SUMMARY FORM
California Public Utilities Commission
MUST BE COMPLETED BY UTILITY (Attach additional pages as needed} Company name/CPUC Utility No.: California Communitv Choice Association Utility type: Contact Person: Evelvn Kahl
IZI ELC □ GAS □ WATER Phone#: (510) 980-9459
E-mail: re2Ulatorv(@cal-cca.org □ PLC □ HEAT E-mail Disposition Notice to: [email protected] EXPLANATION OF UTILITY TYPE (Date Submitted / Received Stamp by CPUC) ELC = Electric GAS = Gas
P WATER = Water July 1, 2024 LC = Pipeline HEAT = Heat
Advice Letter (AL) #: See Attached Tier Designation: 2
Subject of AL: Joint CCA's Community Choice Aggregator Financial Monitoring and Reporting Guidelines Tier 2 Advice L etter Submitted to Aid in the Implementation of Ordering Paragraph 7 of D ecision 24-04-009 Keywords (choose from CPUC listing):

AL Type: D Monthly D Quarterly D Annual IZ] One-Time D Other:

If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution # :

Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: No Summarize differences between the AL and the prior withdrawn or rejected AL: N / A Confidential treatment requested? D Yes [Z] No
If yes, specification of confidential information:

Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and c ontac t information to request nondisclosure agreement/ access to confidential information:

Resolution required? D Yes IZ] No
Requested effective date: 7 / 31/ 24 No. of tariff sheets: N / A Estimated system annual revenue effect(%): N / A
Estimated system average rate effect (%): N / A
When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commerc ial, large C/I, agricultural, lighting).

Tariff schedules affected: N / A
Service affected and changes proposed1' N / A
Pending advice letters that revise the same tariff sheets: N / A 1 Discuss in ALlif mores ace is needed. Clear Form
I
Protests and correspondence regarding this AL are to be sent via email and are due no later than 20 days after the date of this submittal, unless otherwise authorized by the Commission, and shall be sent to:

California Public Utilities Commissio n
Energy Division Tariff Unit Email:

EDT [email protected] .gov
C PUC
Energy Division Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
Contact Name: Evelvn Kahl
Title: G eneral Counsel and D irector of Policy
Utility/Entity Name: California Community Choice Association Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email: regulatorvfa}cal-cca.org
Contact Name: Lauren Carr
Title: Senior Market Policy Analyst
Utility/Entity Name: California Community Choice Association Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email: lauren(li}cal-cca.org
Clear Form
I ENERGY Advice Letter Keywords
Affiliate Direct Access Preliminary Statement
Agreements Disconnect Service Procurement
Agriculture ECAC / Energy Cost Adjustment Qualifying Facility Avoided Cost EO R / Enhanced Oil Recovery Rebates
Balancing Account Energy Charge Refunds
Baseline Energy Efficiency Reliability
Bilingual E stablish Service Re-MAT / Bio-MAT
Billings Expand Service Area Revenue Allocation
Bioenergy Forms Rule 21
Brokerage Fees Franchise Fee / User Tax Rules
CARE GO. 131-D Section 851
CPUC Reimbursement Fee GRC / General Rate Case Self Generation Capacity Hazardous \'Qaste Service Area Map
Cogeneration Increase Rates Service Outage
Compliance Interruptible Service Solar
Conditions of Service Interntility Transportation Standby Service Connection LIEE / Low-Income Energy Efficiency Storage
Con servation LIRA / Low-Income Ratepayer Assistance Street Lights Consolidate Tariffs Late Payment Charge Surcharges
Contracts Line Extensions Tariffs
Core Memorandum Account Taxes
Credit Metered Energy Efficiency Text Changes
Curtailable Service Metering Transformer
Customer Charge Mobile H ome Parks Transition Cost
Customer Owned Generation Name Change Transmission Lines D ecrease Rates Non-Core Transportation Electrification D emand Charge Non-furn Service Contracts Transportation Rates D emand Side Fund Nuclear Undergrnunding
D emand Side Management Oil Pipelines Voltage Discount
D emand Side Response PBR / Performance Based Rat emaking Wind Power D eposits Portfolio Withdrawal of Service
D epreciation Power Lines
Clear Form

ADVICE LETTER

S UMMARY

ENERGY UTILITY
Company name/CPUC Utility No.:

Utility type:

Phone #:

EXPLANATION OF UTILITY TYPE

ELC GAS

PLC HEAT
MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Advice Letter (AL) #:

WATER
E-mail:

E-mail Disposition Notice to:

Contact Person:

ELC = Electric
PLC = Pipeline
GAS = Gas
HEAT = Heat WATER = Water
(Date Submitted / Received Stamp by CPUC)
Subject of AL:

Tier Designation:

Keywords (choose from CPUC listing):

AL Type: Monthly Quarterly Annual One-Time Other:

If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution #:

Does AL replace a withdrawn or rejected AL? If so, identify the prior AL:

Summarize differences between the AL and the prior withdrawn or rejected AL:

Confidential treatment requested? Yes No
If yes, specification of confidential information:

Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/ access to confidential information:

Resolution required? Yes No
Requested effective date: No. of tariff sheets:

Estimated system annual revenue effect (%):

Estimated system average rate effect (%):

When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting).

Tariff schedules affected:

Service affected and changes proposed1:

Pending advice letters that revise the same tariff sheets:
1Discuss in AL if more space is needed.

Marin Clean Energy (MCE)
✔ 415-464-6664
[email protected]
[email protected]
Amulya Yerrapotu
79-E-A 2
Supplemental: 2025 Budget Request and Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff Program

COMPLIANCE
✔
D.24-05-065, E-4999, E-5125,
79-E
✔
This AL makes corrections to the
✔
8/16/24 0
N/A
N/A
N/A
N/A
N/A
Clear Form
California Public Utilities Commission
□ □ □
□ □
□ □ □ □ □
□ □
□ □
I
California Public Utilities Commission
Energy Division Tariff Unit Email:

[email protected]
Protests and correspondence regarding this AL are to be sent via email and are due no later than 20 days after the date of this submittal, unless otherwise authorized by the Commission, and shall be sent to:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

CPUC
Energy Division Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
Policy Analyst
Marin Clean Energy
Amulya Yerrapotu
(925) 378-6729
[email protected]
MCE Regulatory
Regulatory Account
Marin Clean Energy
N/A
N/A
[email protected]
Clear Form
ENERGY Advice Letter Keywords
Affiliate Direct Access Preliminary Statement
Agreements Disconnect Service Procurement
Agriculture ECAC / Energy Cost Adjustment Qualifying Facility Avoided Cost EOR / Enhanced Oil Recovery Rebates
Balancing Account Energy Charge Refunds
Baseline Energy Efficiency Reliability
Bilingual Establish Service Re-MAT/Bio-MAT
Billings Expand Service Area Revenue Allocation
Bioenergy Forms Rule 21
Brokerage Fees Franchise Fee / User Tax Rules
CARE G.O. 131-D Section 851
CPUC Reimbursement Fee GRC / General Rate Case Self Generation Capacity Hazardous Waste Service Area Map
Cogeneration Increase Rates Service Outage
Compliance Interruptible Service Solar
Conditions of Service Interutility Transportation Standby Service Connection LIEE / Low-Income Energy Efficiency Storage
Conservation LIRA / Low-Income Ratepayer Assistance Street Lights Consolidate Tariffs Late Payment Charge Surcharges
Contracts Line Extensions Tariffs
Core Memorandum Account Taxes
Credit Metered Energy Efficiency Text Changes
Curtailable Service Metering Transformer
Customer Charge Mobile Home Parks Transition Cost
Customer Owned Generation Name Change Transmission Lines Decrease Rates Non-Core Transportation Electrification
Demand Charge Non-firm Service Contracts Transportation Rates Demand Side Fund Nuclear Undergrounding
Demand Side Management Oil Pipelines Voltage Discount
Demand Side Response PBR / Performance Based Ratemaking Wind Power Deposits Portfolio Withdrawal of Service
Depreciation Power Lines
Clear Form
MCE Advice Letter 79-E
1 July 8, 2024
California Public Utilities Commission
Energy Division
Attention: Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, CA 94102-3298
MCE Supplemental Advice Letter 79-E-A
RE: Supplemental: 2025 Budget Request and Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff Program

PURPOSE
MCE hereby submits this supplement to Advice Letter 79-E addressing corrections to the 2025 Budget Request and Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff Program that was submitted on July 5, 2024.

This supplemental advice letter is made in accordance with General Order (GO) 96-B and General Rule 7.5.1, which authorizes utilities to make revisions or corrections to advice letters through the submittal of a supplement. This supplement replaces Advice Letter 79-E in part, and Attachment A of Advice Letter 79-E in its entirety.

BACKGROUND
Pursuant to Ordering Paragraphs (“OP”) 2 and 4 of Resolution E-4999,1 OP 3 of Resolution E-5125,2 and OPs 2 and 3 of D.24-05-065,3 Marin Clean Energy (“MCE”) submitted MCE AL-79, the program budget request and marketing, education and outreach (“ME&O”) plan for the Disadvantaged Communities Green Tariff (“DAC-GT) program for the program year (“PY”) 2025, on July 5, 2024.

On page 4 of Attachment A, in Table 1: MCE Budget Forecast for PY 2025, MCE inadvertently 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 OP 2 of D.24-05-065 discontinues the CS-GT program and directs program administrators to transfer remaining capacity, customers, and programs into the DAC-GT program. OP 3 of D.24-05-065 makes several modifications to the DAC-GT program, which are reflected in this budget submission.

Empowering Our Clean Energy Future

MARIN COUNTY I NAPA COUNTY I UNINCORPORATED CONTRA COSTA COUNTY

UNINCORPORATED SOLANO COUNTY I BENICIA I CONCORD I DANVILLE I EL CERRITO

FAIRFIELD I HERCULES I LAFAYETTE I MARTINEZ I MORAGA I OAKLEY I PINOLE

PITTSBURG I PLEASANT HILL I RICHMOND I SAN PABLO I SAN RAMON I WALNUT CREEK MCE Advice Letter 79-E
2 used an incorrect value for the Generation Cost Delta, incorrectly inflating energy consumption from program participants by 25%. This, in turn, impacts subsequent sums (Total DAC-GT PY 2025 Budget Forecast, Total DAC-GT Budget Request for PY 2025, and Total MCE Budget Request for PY 2025).

After correcting the error, the 2025 Generation Cost Delta, Total DAC-GT PY 2025 Budget Forecast, Total DAC-GT Budget Request for PY 2025, and Total MCE Budget Request are all reduced by $489,242.61. MCE now requests a total budget of $6,302,724 for PY 2025.

MCE is submitting a revised Attachment A to correct the error. Please discard the previously submitted Attachment A in its entirety.

PROPOSED MODIFICATIONS TO ADVICE LETTER 79-E
MCE proposes the following modification to Advice Letter 79-E, as shown in bold font. “MCE hereby submits the budget request for PY 2025 for the DAC-GT program. Per Resolution E-4999, the budget request includes both the budget reconciliation for the previous PY (i.e., PY 2023) and the budget forecast for the upcoming PY (i.e., PY 2025). Because D.24-05-065 closes the CS-GT program for future procurement and MCE has not already procured a project for the CS-GT program, MCE does not include CS-GT in the PY 2025 budget forecast. However, MCE continues to include CS-GT program costs in the PY 2023 budget reconciliation. In summary, MCE requests a total budget of $6,302,724 for the DAC-GT program for PY 2025, including PY 2023 CS-GT reconciliation costs. Additional details can be found in Appendix A.”

TIER DESIGNATION
This supplemental AL is submitted with a Tier 2 designation, the same Tier designation pursuant to OP 3 of Resolution E-5125.

EFFECTIVE DATE
MCE requests that this supplemental AL become effective concurrent with the original AL 79-E, 30 calendar days from the July 5, 2024 date filing.

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
MCE Advice Letter 79-E
3 MCE requests that the Commission, pursuant to General Order 96-B, General Rule 7.5.1, maintain the original protest and comment period designated in advice letter 79-E. 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 Analyst
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 (925) 378-6729 or by electronic mail at [email protected].
/s/ Amulya Yerrapotu
Amulya Yerrapotu
Policy Analyst

MARIN CLEAN ENERGY
1125 Tamalpais Avenue
San Rafael, CA 94901
Telephone: (925) 378-6729
Email: [email protected]
Appendices
Appendix A: PY 2025 Budget Request
Appendix B: PY 2025 ME&O Plan
cc: Service List for R.14-07-002 and A.22-05-022
A-1
Budget Forecast for the Disadvantaged Communities Green Tariff Program for Program Year 2025
Proposed by Marin Clean Energy
MCE
A-2

TABLE OF CONTENTS

1. BACKGROUND 3

2. BUDGET FORECAST FOR PY 2025 4

3. BUDGET CAPS 6

4. BUDGET RECONCILIATION FOR PY 2023 6

5. 2025 BUDGET REQUEST 8

6. PROGRAM CAPACITY AND ENROLLMENT NUMBERS 8

TABLE OF FIGURES
Table 1: MCE Budget Forecast for PY 2025 4
Table 2: MCE Budget Reconciliation for PY 2023 8
Table 3: MCE Budget Request for PY 2025 9
Table 4: Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2023 9 Table 5: Forecasted Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2025 9

A-3

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 2023) and the budget forecast for the upcoming PY (i.e., PY 2025). As D.24- 05-065 closes the CS-GT program for future procurement and MCE has not already procured a CS-GT project, MCE does not include CS-GT program costs for PY 2025, and only includes CS-GT costs in the budget reconciliation for PY 2023, but does not include CS-GT program costs for PY 2025.

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, 2023);

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, 2023); and 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 9costs 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 2025 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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4. Forecasted customer enrollment for the upcoming PY.

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 2025
For PY 2025, MCE forecasts a total budget of $5,456,986 for the DAC-GT program. This budget forecast accounts for the program modifications established in D.24-05-065, including discontinuing the CS-GT program and rolling unused capacity into the DAC-GT program, increasing DAC-GT program capacity, and removing the Green-e certification requirement. 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 2025
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 Category DAC-GT
Generation Cost Delta $ 1,956,970
20% Bill Discount $ 3,310,666
Program Administration
Program Management $ 22,820
Information Technology $ 11,617
Billing Operations $ 98,868
Regulatory Compliance $ 18,996
Procurement $ 15,690
Subtotal Program Administration $ 167,991
Marketing, Education & Outreach
Labor Costs $ 6,357
Outreach and Material Costs $ 15,000
Subtotal ME&O $ 21,357
Total $ 5,456,985
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granted MCE’s request to approve its dedicated DAC-GT power purchase agreement (PPA).4 On November 11, 2024, the Commission approved MCE’s first request to amend its dedicated DAC-GT PPA. On June 19, 2024, the Commission approved MCE’s second request to amend its dedicated DAC-GT PPA. The new dedicated solar generation facility is expected to come online in early 2026. As such, the DAC-GT generation cost delta budget forecast for 2025 is based on the PPA price of the current interim solar generation resource, compared to the costs of serving customers under MCE’s residential base tariff, the “Light Green” tariff.

Decision 24-05-065 approves a 50% expansion of MCE’s DAC-GT program capacity. Decision 24-05-065 also rolls any unused CS-GT capacity into MCE’s DAC-GT program. MCE’s DAC-GT program now has a total capacity of 8.249 MW. MCE plans to enroll customers using an interim resource as it works to procure a resource to serve the remaining program capacity. MCE anticipates using the existing DAC-GT interim resource for this purpose. 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 participating customers.

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 2025, MCE expects to have approximately 5,805 customers enrolled in the DAC-GT program. D.24-05-065 expands MCE’s DAC-GT program capacity by 3.609 MW. MCE estimates that it will be able to serve 2,540 customers with this new capacity, in addition to the existing 3,265 customers currently served by existing program capacity. MCE plans to enroll customers using an interim resource as it works to procure a new resource to serve the remaining program capacity.

The PY 2025 forecast for the 20 percent bill discount is based on the actual average monthly bill discount provided to participating customers in 2023, with a 25% increase to account for forecasted increases in electricity rates. Future customers enrolled under the expanded capacity are assumed to have the same usage as existing customers.

Program Administration Costs
Program administration 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. While D.24-05-065 directs PG&E to provide a cost estimate for implementing an automated billing solution, it is uncertain whether such a solution will be implemented. As such, for the time being, MCE assumes that billing costs will remain as they are now. Regulatory Compliance 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. D.24-05-065 removes the Green-e certification requirement, instead ordering program 4 See Disposition of MCE AL 63-E, MCE Disadvantaged Communities Green Tariff Program 2022 Power Purchase Agreement Approval.
5 Resolution E-5124, p. 12.

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administrators to independently track the retirement of RECs. MCE estimates those costs in the procurement forecast.

Marketing, Education and Outreach (ME&O)
ME&O budgets are split in two categories – (1) MCE labor costs; and (2) MCE direct costs for outreach and material.

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 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 for additional review of this and other ABAL components.8 The 2025 budget forecast summarized above in Table 1 results in DAC-GT program administration budgets of 3% and ME&O budgets of 0%. As such, MCE does not require an adjustment to the program administration budget cap for DAC-GT for PY 2025.

4. BUDGET RECONCILIATION FOR PY 2023
MCE submitted a budget forecast for PY 2023 as a part of its 2023 Budget Request and Marketing, Education, and Outreach Plan in AL 58-E on February 1, 2022. The table below shows the forecasted and actual costs for PY 2023 per budget line item, as well as the true-up amount that will be carried forward to future program years.
6 Resolution E-4999, p. 27.
7 Resolution E-5125, p. 7.
8 Id.

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Table 2: MCE Budget Reconciliation for PY 2023
Category
Forecast Actual
True-up (Actual -
Forecast) Forecast Actual
True-up (Actual -
Forecast)
Generation Cost Delta $ 988,083 $ 994,287 $ 6,204 $ - - $ $ - 20% Bill Discount $ 280,035 $ 1,489,780 $ 1,209,745 $ - - $ $ - Program Administration
Program Management $ 84,050 $ 10,125 $ (73,925) $ 97,150 $ 3,062 $ (94,088) Information Technology $ 30,537 $ 7,343 $ (23,194) $ 19,009 $ 1,531 $ (17,478) Billing Operations $ 76,735 $ 89,913 $ 13,178 $ 34,422 $ 1,531 $ (32,891) Regulatory Compliance $ 7,860 $ 27,582 $ 19,722 $ 7,860 $ 18,510 $ 10,650 Procurement $ 26,815 $ 25,189 $ (1,626) $ 31,093 $ 1,834 $ (29,259) CCA Integration Costs $ 2,430 $ 1,623 $ (807) $ - - $ $ - Subtotal Program Administration $ 228,427 $ 161,775 $ (66,652) $ 189,534 $ 26,468 $ (163,066) Marketing, Education & Outreach
Labor Costs $ 21,615 $ 3,220 $ (18,395) $ 59,605 $ 2,260 $ (57,345) Outreach and Material Costs $ 20,000 $ 6,248 $ (13,752) $ - 26,000 $ $ (26,000) Local CBO/ Sponsor Costs $ - - $ $ - $ - 25,000 $ $ (25,000) Subtotal ME&O $ 41,615 $ 9,469 $ (32,146) $ 110,605 $ 2,260 $ (108,345) Total $ 1,538,160 $ 2,655,310 $ 1,117,150 $ 300,139 $ 28,728 $ (271,411)

DAC-GT CS-GT
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5. 2025 BUDGET REQUEST
Based on the budget forecast for PY 2025 presented in Section 2 and the budget reconciliation for PY 2023 presented in section 4, MCE is requesting a total budget of $6,302,724 for the DAC-GT and CS-GT programs in this budget AL.

Table 3: MCE Budget Request for PY 2025

6. PROGRAM CAPACITY AND ENROLLMENT NUMBERS
MCE reports existing program capacity and customer enrollment numbers as of December 31, 2023 in Table 4 below. In PY 2023, 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 2023 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 2025. As noted above, MCE estimates that the dedicated project to serve existing DAC-GT will come online in early 2026. MCE plans to solicit a new project to serve the expanded DAC-GT capacity granted in D.24-05-065, but does not anticipate this project will come online during PY 2025. MCE plans to enroll additional customers under the expanded capacity using an interim resource until a new resource can be procured.

Table 5: Forecasted Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2025
Category DAC-GT
Existing program capacity (MW) 4.646
Additional program capacity to be procured (MW) 3.609
Total program capacity (MW) 8.249
Estimated customer enrollment (#) 5,805
DAC-GT CS-GT Total
Budget Carry-over from PY 2023 $ 1,117,150 $ (271,411) $ 845,739 Budget Forecast for PY 2025 $ - 5,456,985 $ $ 5,456,985 TOTAL $ 6,574,135 $ (271,411) $ 6,302,724

ADVICE LETTER

SUMMARY

ENERGY UTILITY
Company name/CPUC Utility No.:

Utility type:

Phone #:

EXPLANATION OF UTILITY TYPE

ELC GAS

PLC HEAT
MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Advice Letter (AL) #:

WATER
E-mail:

E-mail Disposition Notice to:

Contact Person:

ELC = Electric
PLC = Pipeline
GAS = Gas
HEAT = Heat WATER = Water
(Date Submitted / Received Stamp by CPUC)
Subject of AL:

Tier Designation:

Keywords (choose from CPUC listing):

AL Type: Monthly Quarterly Annual One-Time Other:

If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution #:

Does AL replace a withdrawn or rejected AL? If so, identify the prior AL:

Summarize differences between the AL and the prior withdrawn or rejected AL:

Confidential treatment requested? Yes No
If yes, specification of confidential information:

Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/ access to confidential information:

Resolution required? Yes No
Requested effective date: No. of tariff sheets:

Estimated system annual revenue effect (%):

Estimated system average rate effect (%):

When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting).

Tariff schedules affected:

Service affected and changes proposed1:

Pending advice letters that revise the same tariff sheets:
1 Discuss in AL if more space is needed.

California Public Utilities Commission
California Public Utilities Commission
Energy Division Tariff Unit Email:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

CPUC
Energy Division Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
ENERGY Advice Letter Keywords
Affiliate Direct Access Preliminary Statement
Agreements Disconnect Service Procurement
Agriculture ECAC / Energy Cost Adjustment Qualifying Facility Avoided Cost EOR / Enhanced Oil Recovery Rebates
Balancing Account Energy Charge Refunds
Baseline Energy Efficiency Reliability
Bilingual Establish Service Re-MAT/Bio-MAT
Billings Expand Service Area Revenue Allocation
Bioenergy Forms Rule 21
Brokerage Fees Franchise Fee / User Tax Rules
CARE G.O. 131-D Section 851
CPUC Reimbursement Fee GRC / General Rate Case Self Generation Capacity Hazardous Waste Service Area Map
Cogeneration Increase Rates Service Outage
Compliance Interruptible Service Solar
Conditions of Service Interutility Transportation Standby Service Connection LIEE / Low-Income Energy Efficiency Storage
Conservation LIRA / Low-Income Ratepayer Assistance Street Lights Consolidate Tariffs Late Payment Charge Surcharges
Contracts Line Extensions Tariffs
Core Memorandum Account Taxes
Credit Metered Energy Efficiency Text Changes
Curtailable Service Metering Transformer
Customer Charge Mobile Home Parks Transition Cost
Customer Owned Generation Name Change Transmission Lines Decrease Rates Non-Core Transportation Electrification
Demand Charge Non-firm Service Contracts Transportation Rates Demand Side Fund Nuclear Undergrounding
Demand Side Management Oil Pipelines Voltage Discount
Demand Side Response PBR / Performance Based Ratemaking Wind Power Deposits Portfolio Withdrawal of Service
Depreciation Power Lines
MCE Advice Letter 79-E
1 July 8, 2024
California Public Utilities Commission
Energy Division
Attention: Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, CA 94102-3298
MCE Advice Letter 79-E
RE: 2025 Budget Request and Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff Program
Pursuant to Ordering Paragraphs (“OP”) 2 and 4 of Resolution E-4999,1 OP 3 of Resolution E-5125,2 and OPs 2 and 3 of D.24-05-065,3 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) program for the program year (“PY”) 2025.

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 August 8, 2024, 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 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 OP 2 of D.24-05-065 discontinues the CS-GT program and directs program administrators to transfer remaining capacity, customers, and programs into the DAC-GT program. OP 3 of D.24-05-065 makes several modifications to the DAC-GT program, which are reflected in this budget submission.

Empowering Our Clean Energy Future

MARIN COUNTY I NAPA COUNTY I UNINCORPORATED CONTRA COSTA COUNTY

UNINCORPORATED SOLANO COUNTY I BENICIA I CONCORD I DANVILLE I EL CERRITO

FAIRFIELD I HERCULES I LAFAYETTE I MARTINEZ I MORAGA I OAKLEY I PINOLE

PITTSBURG I PLEASANT HILL I RICHMOND I SAN PABLO I SAN RAMON I WALNUT CREEK MCE Advice Letter 79-E
2 renewable generation among residential customers in disadvantaged communities (“DACs”),4 as 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.5 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.6 Furthermore, the Resolution specifies that Program Administrators must reconcile prior year budget forecasts and expenditures in their annual budget requests.7 On December 4, 2023, MCE, as a part of the Joint CCAs, requested a two-month extension of the budget AL until April 1, 2023. On January 11, 2024, MCE, as a part of the Joint CCAs, amended the extension request to align with the IOUs, requesting an extension until May 1, 2024, or 30 days after the issuance of the Final Decision in proceeding A.22-05-022, whichever is later. On January 24, 2024, the Joint CCAs’ extension request was granted. The Final Decision in proceeding A.22- 05-022 was issued on June 7, 2024.8
On May 30, 2024, the CPUC approved D.24-05-065, discontinuing the CS-GT program and approving a number of modifications to the DAC-GT program. The DAC-GT program modifications pertaining to CCA program administrators include: modifying project siting requirements, increasing program capacity, allowing the voluntarily inclusion of storage in projects, ordering the cost containment cap to be updated, changing the budget advice letter deadline to April 1st, and removing the Green-e certification requirement.

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 to 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 of the programs. Therefore, MCE is submitting this advice letter to ensure timely cost recovery for its programs.
4 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 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. 5 D.18-06-027, p. 104, OP 17. 6 Resolution E-4999, OP 2.
7 Resolution E-4999, OP 4.
8 D.24-05-065
MCE Advice Letter 79-E
3 PURPOSE
MCE hereby submits the budget request for PY 2025 for the DAC-GT program. Per Resolution E-4999, the budget request includes both the budget reconciliation for the previous PY (i.e., PY 2023) and the budget forecast for the upcoming PY (i.e., PY 2025). Because D.24-05-065 closes the CS-GT program for future procurement and MCE has not already procured a project for the CS-GT program, MCE does not include CS-GT in the PY 2025 budget forecast. However, MCE continues to include CS-GT program costs in the PY 2023 budget reconciliation. In summary, MCE requests a total budget of $6,791,967 for the DAC-GT program for PY 2025, including PY 2023 CS-GT reconciliation costs. 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 program in the 2025 ERRA Forecast filing.9 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 balancing account. PG&E will then transfer program funds to MCE as determined in Resolution E-5124.10 In addition to the budget request, MCE submits its updated ME&O plan for PY 2025 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 requests approval of its ME&O plan for 2025.

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
9 D.22-01-023, p. 28, OP 3. Modifies the due date for PG&E to file this annual Application to May 15, 2023. Because D.24-05-065 was not voted on until May 30, 2024, pushing this advice letter filing to July 8th, 2024 PG&E may need to include an updated budget in its October ERRA forecast update. 10 Resolution E-5124, p. 10.

MCE Advice Letter 79-E
4 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:

CORRESPONDENCE
For questions, please contact Amulya Yerrapotu at (925) 378-6729 or by electronic mail at [email protected].
/s/ Amulya Yerrapotu
Amulya Yerrapotu
Policy Analyst

TABLE OF CONTENTS

1. BACKGROUND 3

2. BUDGET FORECAST FOR PY 2025 4

3. BUDGET CAPS 6

4. BUDGET RECONCILIATION FOR PY 2023 6

5. 2025 BUDGET REQUEST 8

6. PROGRAM CAPACITY AND ENROLLMENT NUMBERS 8

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).

1. Existing solar generation capacity at previous PY’s close (i.e., December 31, 2023);

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, 2023); and 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 2025 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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4. Forecasted customer enrollment for the upcoming PY.

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 2025
For PY 2025, MCE forecasts a total budget of $5,946,227 for the DAC-GT program. This budget forecast accounts for the program modifications established in D.24-05-065, including discontinuing the CS-GT program and rolling unused capacity into the DAC-GT program, increasing DAC-GT program capacity, and removing the Green-e certification requirement. 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 2025
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 Category DAC-GT
Generation Cost Delta $ 2,446,213
20% Bill Discount $ 3,310,666
Program Administration
Program Management $ 22,820
Information Technology $ 11,617
Billing Operations $ 98,868
Regulatory Compliance $ 18,996
Procurement $ 15,690
Subtotal Program Administration $ 167,991
Marketing, Education & Outreach
Labor Costs $ 6,357
Outreach and Material Costs $ 15,000
Subtotal ME&O $ 21,357
Total $ 5,946,227
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granted MCE’s request to approve its dedicated DAC-GT power purchase agreement (PPA).4 On November 11, 2024, the Commission approved MCE’s first request to amend its dedicated DAC-GT PPA. On June 19, 2024, the Commission approved MCE’s second request to amend its dedicated DAC-GT PPA. The new dedicated solar generation facility is expected to come online in early 2026. As such, the DAC-GT generation cost delta budget forecast for 2025 is based on the PPA price of the current interim solar generation resource, compared to the costs of serving customers under MCE’s residential base tariff, the “Light Green” tariff.

Program Administration Costs
Program administration includes program development, management, budgeting, and reporting.

A-6
administrators to independently track the retirement of RECs. MCE estimates those costs in the procurement forecast.

Marketing, Education and Outreach (ME&O)
ME&O budgets are split in two categories – (1) MCE labor costs; and (2) MCE direct costs for outreach and material.

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Table 2: MCE Budget Reconciliation for PY 2023
Category
Forecast Actual
True-up (Actual -
Forecast) Forecast Actual
True-up (Actual -
Forecast)
Generation Cost Delta $ 988,083 $ 994,287 $ 6,204 $ - $ - $ - 20% Bill Discount $ 280,035 $ 1,489,780 $ 1,209,745 $ - $ - $ - Program Administration
Program Management $ 84,050 $ 10,125 $ (73,925) $ 97,150 $ 3,062 $ (94,088) Information Technology $ 30,537 $ 7,343 $ (23,194) $ 19,009 $ 1,531 $ (17,478) Billing Operations $ 76,735 $ 89,913 $ 13,178 $ 34,422 $ 1,531 $ (32,891) Regulatory Compliance $ 7,860 $ 27,582 $ 19,722 $ 7,860 $ 18,510 $ 10,650 Procurement $ 26,815 $ 25,189 $ (1,626) $ 31,093 $ 1,834 $ (29,259) CCA Integration Costs $ 2,430 $ 1,623 $ (807) $ - $ - $ - Subtotal Program Administration $ 228,427 $ 161,775 $ (66,652) $ 189,534 $ 26,468 $ (163,066) Marketing, Education & Outreach
Labor Costs $ 21,615 $ 3,220 $ (18,395) $ 59,605 $ 2,260 $ (57,345) Outreach and Material Costs $ 20,000 $ 6,248 $ (13,752) $ 26,000 $ - $ (26,000) Local CBO/ Sponsor Costs $ - $ - $ - $ 25,000 $ - $ (25,000) Subtotal ME&O $ 41,615 $ 9,469 $ (32,146) $ 110,605 $ 2,260 $ (108,345) Total $ 1,538,160 $ 2,655,310 $ 1,117,150 $ 300,139 $ 28,728 $ (271,411)

DAC-GT CS-GT
A-8

5. 2025 BUDGET REQUEST
Based on the budget forecast for PY 2025 presented in Section 2 and the budget reconciliation for PY 2023 presented in section 4, MCE is requesting a total budget of $6,791,967 for the DAC-GT and CS-GT programs in this budget AL.

Table 3: MCE Budget Request for PY 2025

Table 5: Forecasted Program Capacity and Enrollment Count for DAC-GT and CS-GT for PY 2025
Category DAC-GT
Existing program capacity (MW) 4.646
Additional program capacity to be procured (MW) 3.609
Total program capacity (MW) 8.249
Estimated customer enrollment (#) 5,805
DAC-GT CS-GT Total
Budget Carry-over from PY 2023 $ 1,117,150 $ (271,411) $ 845,739 Budget Forecast for PY 2025 $ 5,946,227 $ - $ 5,946,227 TOTAL $ 7,063,378 $ (271,411) $ 6,791,967
Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff and Community Solar Green Tariff Programs for Program Year 2025
Proposed by Marin Clean Energy
MCE

TABLE OF CONTENTS

1. PURPOSE AND GOALS.......................................................................................................... 1

2. GUIDING PRINCIPLES.......................................................................................................... 1

3. TARGET AUDIENCE............................................................................................................. 1

4. ME&O TACTICS AND STRATEGIES ...................................................................................... 3

5. METRICS TRACKING .......................................................................................................... 3

TABLE OF FIGURES
Figure 1. Qualifying Neighborhoods in MCE Service Area for DAC-GT Auto-Enrollment 2 1 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) program to ensure potential customers in disadvantaged communities (DACs) are aware of the benefits from the program.

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.

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).

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 program. 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.

3. TARGET AUDIENCE
Upon the launch of the DAC-GT program in 2021, MCE automatically enrolled eligible customers who live in one of the top 10% of DAC census tracts statewide, as defined by CalEnviroScreen

3.0, and who reside within MCE’s service area. Priority was given to customers who made an effort to pay, as defined by making at least four full or partial payments in the preceding eight months. With the expanded capacity of the DAC-GT program, MCE will enroll additional customers as identified by CalEnviroScreen 4.0 in the following order:

1. Customers who live in one of the top 25% of DAC census tracts and are enrolled in the Arrearage Management Program (category 1);

2. Customers who live in one of the top 25% of DAC census tracts and are in arrears (category 2); and then

3. All other customers who live in one of the top 25% of DAC census tracts (category 3). 2 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 based on the above criteria 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 75% CalEnviroScreen 4.0 Score
Census Tract California
County ZIP
Nearby City
(to help approximate
location only)
6013305000 Contra Costa 94509 Antioch
6013306002 Contra Costa 94509 Antioch
6013306003 Contra Costa 94509 Antioch
6013307102 Contra Costa 94509 Antioch
6013309000 Contra Costa 94565 Pittsburg
6013310000 Contra Costa 94565 Pittsburg
6013311000 Contra Costa 94565 Pittsburg
6013312000 Contra Costa 94565 Pittsburg
6013314102 Contra Costa 94565 Pittsburg
6013314103 Contra Costa 94565 Pittsburg
6013314104 Contra Costa 94565 Pittsburg
6013314200 Contra Costa 94565 Pittsburg
6013327000 Contra Costa 94520 Concord
6013336201 Contra Costa 94520 Concord
6013358000 Contra Costa 94572 Rodeo
6013365002 Contra Costa 94801 Richmond
6013366002 Contra Costa 94806 San Pablo
6013368001 Contra Costa 94806 San Pablo
6013368002 Contra Costa 94806 San Pablo
6013369001 Contra Costa 94806 San Pablo
6013375000 Contra Costa 94801 Richmond
6013376000 Contra Costa 94801 Richmond
6013377000 Contra Costa 94801 Richmond
6013379000 Contra Costa 94804 Richmond
6013380000 Contra Costa 94804 Richmond
6013381000 Contra Costa 94804 Richmond
6013382000 Contra Costa 94804 Richmond
6013392200 Contra Costa 94806 San Pablo
6095250701 Solano 94590 Vallejo
6095250801 Solano 94592 Vallejo
3 6095250900 Solano 94590 Vallejo
6095251000 Solano 94590 Vallejo
6095251600 Solano 94590 Vallejo
6095251802 Solano 94589 Vallejo
6095251803 Solano 94589 Vallejo
6095251901 Solano 94589 Vallejo
6013314103 Contra Costa 94565 Pittsburg
6013314102 Contra Costa 94565 Pittsburg
6013306002 Contra Costa 94509 Antioch

4. ME&O TACTICS AND STRATEGIES
MCE will leverage the communications and media content originally developed to promote DAC-GT, including direct mailers, email, and webpage.

5. METRICS TRACKING
MCE will use a variety of metrics to evaluate the effectiveness of each effort. The primary measure of effectiveness used will be the number of customers reached, which will be measured by:
• Number of customers enrolled based on auto enrollment criteria; • Number of customers found to be ineligible for the program based on eligibility criteria; • Number of customers opting to cancel program participation; and • Number of customers to be enrolled from the waitlist based on the capacity provided through the total sum of all aforementioned attributes.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric Company
(U39E) for Review of the Disadvantaged
Communities – Green Tariff, Community Solar
Green Tariff and Green Tariff Shared Renewables
Programs.

A.22-05-022
And Related Matters. A.22-05-023
A.22-05-024

OPENING COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS

AND CITY AND COUNTY OF SAN FRANCISCO ON ADMINISTRATIVE LAW JUDGE’S RULING DIRECTING RESPONSES TO QUESTIONS REGARDING IMPLEMENTATION OF DECISION 24-05-065
Brittany Iles
BRAUN BLAISING & WYNNE, P.C.
555 Capitol Mall, Suite 570
Sacramento, CA 95814
Telephone: (916) 326-5812
E-mail: [email protected]
July 10, 2024 Attorney for the
Joint Community Choice Aggregators and
City and County of San Francisco
i

TABLE OF CONTENTS
I. INTRODUCTION .................................................................................................................. 1 II. SUMMARY OF CCA CRE PROGRAM PROPOSAL .......................................................... 3 A. The New CRE Program Must Equally Incorporate IOU and CCA Tariffs......................... 3 i. Proposed CRE Contract Structure and Project Requirements........................................ 4 ii. CRE Customer Eligibility ............................................................................................... 7 B. Any CRE Program Implemented by the Commission Must Take Into Account Current Funding Limitations.................................................................................................................... 8 III. RESPONSES TO RULING QUESTIONS: NEW COMMUNITY RENEWABLE ENERGY PROGRAM.................................................................................................................. 10 A. Revenue Share and Bill Credits........................................................................................ 10 i. Developer Compensation...............................................................................................11 ii. Participant Revenue Share (or “Customer Incentive”)................................................. 14 B. Non-Ratepayer-Funded Adder.......................................................................................... 18 C. Federal Incentives............................................................................................................. 20 D. Disbursal of Non-Ratepayer Funds................................................................................... 20 E. Treatment of Utility Implementation and Administrative Costs....................................... 21 F. CCA Participation ............................................................................................................. 22 G. Enrollment......................................................................................................................... 23 IV. RESPONSES TO RULING QUESTIONS: MODIFIED DISADVANTAGED COMMUNITIES GREEN TARIFF PROGRAM......................................................................... 25 V. RESPONSES TO RULING QUESTIONS: MODIFIED AND LEGACY GREEN TARIFF AND SHARED RENEWABLES ................................................................................................. 27 A. Incremental Renewable Procurement – All Parties Respond ........................................... 27 VI. RESPONSES TO RULING QUESTIONS: ALL CALIFORNIA RENEWABLES PORTFOLIO PROGRAMS.......................................................................................................... 28 VII. CONCLUSION................................................................................................................. 29 1 BEFORE THE PUBLIC UTILITIES COMMISSION

A.22-05-022
And Related Matters. A.22-05-023
A.22-05-024

OPENING COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS

AND CITY AND COUNTY OF SAN FRANCISCO ON ADMINISTRATIVE LAW JUDGE’S RULING DIRECTING RESPONSES TO QUESTIONS REGARDING IMPLEMENTATION OF DECISION 24-05-065
I. INTRODUCTION
In accordance with the California Public Utilities Commission’s (“CPUC” or “Commission”) Administrative Law Judge’s Ruling Directing Response to Questions Regarding Implementation of Decision 24-05-065 dated June 5, 2024 (“ALJ Ruling” or “Ruling”), Ava Community Energy, Clean Power Alliance of Southern California, the City and County of San Francisco, acting by and through its Public Utilities Commission, Lancaster Choice Energy, Marin Clean Energy, Peninsula Clean Energy Authority, Pico Rivera Innovative Municipal Energy, San Diego Community Power, San Jacinto Power, and San José Clean Energy (collectively, the “Joint Community Choice Aggregators” or “Joint CCAs”) hereby submit these Opening Comments.

The Joint CCAs appreciate the Commission’s aim to expeditiously resolve implementation issues associated with the modified Disadvantaged Communities Green Tariff (“DAC-GT”) and the new Community Renewable Energy (“CRE”) programs as adopted by 2 Decision (“D.”) 24-05-065, Decision Modifying Green Access Program Tariffs and Adopting a Community Renewable Energy Program (“the Decision”). The Joint CCAs support the Commission’s goal of furthering the development of local, front-of-the-meter (“FTM”) distributed energy resources (“DERs”) – community solar and storage resources in particular – and look forward to collaborating with the Commission on developing the details that would allow interested Community Choice Aggregators (“CCAs”) to offer a CCA-led CRE Program.

As noted in the Ruling and the Decision, the record does not contain specifics for CCA participation, and there are open questions associated with which tariffs and processes should be in place to enable interested CCAs to participate in the CRE Program. 1 In these comments, the
Joint CCAs outline the cornerstones of a proposed CRE Program that can incorporate both investor-owned utility (“IOU”) and CCA tariffs. While the Joint CCAs propose to largely align the CRE Program between IOU and CCA administrators, there are a few instances where program rules may differ (as further outlined below).

The Joint CCAs’ comments are structured in three sections. Section II provides a summary of the Joint CCAs’ CRE Program proposal and highlights concerns regarding the financial viability of the CRE Program with current funding allocations. Section III answers specific questions in the ALJ Ruling regarding the CRE Program, providing additional details regarding the Joint CCAs’ CRE Program proposal as it relates specifically to developer compensation and the “subscriber revenue share” (referred to hereafter as “customer incentives”). Finally, Sections IV through VI respond to select Ruling questions regarding the modification of the DAC-GT program.
1 See D.24-05-065 at 148 (“As CCAs are permitted to participate in the new community renewable energy program, the foundational tariffs will need to be revised to accommodate this participation. At this time, the record does not contain the specifics for CCA participation”); see also Ruling at 7 (requesting comment on which process should be employed to enable CCA participation). 3 II. SUMMARY OF CCA CRE PROGRAM PROPOSAL
A. The New CRE Program Must Equally Incorporate IOU and CCA Tariffs The Joint CCAs support greater development of distributed FTM resources, and appreciate the opportunity to provide feedback on the new CRE Program to ensure that interested CCAs will be able to participate. The Decision specifies that the new CRE Program shall be based on one of the existing IOU tariffs that are compliant with the federal Public Utility Regulatory Policies Act (“PURPA”), such as the Renewable Market Adjusting Tariff (“ReMAT”) and Standard-Offer-Contract (“SOC”) tariffs.2 However, as these are IOU-specific tariffs, the Commission also notes in the Decision that “the foundational tariffs will need to be revised to accommodate” CCA participation.3 The Joint CCAs propose that both IOUs and CCAs use SOCs as foundational tariffs for the CRE Program. Specifically, the Joint CCAs propose to offer a SOC tariff that incorporates the IOUs’ PURPA wholesale tariffs but which is governed by CCA tariff rules and principles. As noted above, the Joint CCAs recommend that program rules and requirements should largely be aligned between IOUs and CCAs offering the CRE Program, as is customary under the existing DAC-GT programs. This would ensure consistency between the various CRE Programs and would minimize confusion among customers and developers. As such, the Joint CCA proposal illustrated below would be consistent across both IOU and CCA program administrators with limited exceptions.

The Joint CCAs provide the following proposal as the basic underlying structure of the CRE Program, detailing the program’s contract structure and project requirements. Further details regarding developer compensation and customer incentives are provided in Section III in response to the ALJ Ruling questions.
2 D.24-05-065 at 168, Ordering Paragraph (“OP”) 1(a).
3 Id. at 148.
4 i. Proposed CRE Contract Structure and Project Requirements Similar to the IOUs, the Joint CCAs propose that interested CCAs would offer SOCs under the CRE Program in which a developer signs a power purchase agreement (“PPA”) directly with the load serving entity (“LSE”) (i.e., in this case, the CCA) for a 20-year delivery term. The 20-year delivery term is recommended to enable subscribing customers to meet Title 24 requirements by enrolling under a CRE project.

The Joint CCAs believe the CRE Program should be based on SOCs because this contract structure allows the developers insight into PPA prices, which in turn helps them assess the feasibility of project development. One of the hurdles the Joint CCAs have encountered under the DAC-GT and Community Solar Green Tariff (“CSGT”) programs has been that developers are uncertain about the cost cap for PPAs because that information is confidential. The Joint CCAs understand that developers may choose not to participate in DAC-GT or CSGT solicitations due to the perception that the prices for their projects may be too high. A set PPA price under a SOC construct would remove this uncertainty. This construct would also reduce PPA negotiations and bid pricing reviews, leading to program administration efficiencies and price consistency for customers throughout the state.

As detailed further in response to Question 1 in Section III below, the Joint CCAs are proposing that the CRE Program PPA price be based on several components, including a PPA base payment and additional price adders. Consistent with the Decision, the Joint CCAs propose that the PPA base payment would be based on the PURPA avoided costs for both IOU and CCA projects,4 with additional “adders” provided to appropriately value the local DERs. While the 4 Id. at 125 (“The adopted community renewable energy program will compensate generating resources based on the PURPA avoided costs of the facility…[T]he Commission will use its own method to determine the avoided cost of the generating resource, with PURPA guidance.”) 5 Joint CCAs are amenable to adopting the PURPA avoided costs as the base PPA price under the CRE Program, it must be highlighted that CCAs do not fall under PURPA compliance and CCA avoided generation costs are likely to differ from the IOUs’ avoided costs.

The CRE Program resources would consist of solar, or solar plus storage, projects. 5 The
Joint CCAs propose certain locational requirements to support community-based solar or solar plus storage projects, and to ensure that projects are located in areas where the load (or customer) is located. In the case of a CCA offering the CRE Program, one could argue that the resource is implicitly “local” if it is located in a CCA’s (more geographically limited) service area and will only serve CCA customers. However, the same is not necessarily true for IOU projects due to the vast size of the IOUs’service territories.
6 For these reasons, the Joint CCAs propose that CRE
projects must be located within 50 miles of subscribing customers for both IOU and CCA-led CRE Programs (or vice versa, subscribing customers must be located within 50 miles of the CRE resource). The Joint CCAs are open to considering other locational requirements as proposed by stakeholders in response to this Ruling.

Additionally, CRE resources must be integrated into the California Independent System Operator (“CAISO”) market. It is essential that resources under the program can receive resource adequacy (“RA”) credit. However, RA credits are only possible if the resource can receive deliverability status, which has been an observed barrier for distributed resources because the deliverability allocation process is an ill fit for projects of this type. If it is cost prohibitive or otherwise not feasible for the resource to get deliverability, the Commission should work with 5 Id. at 169, OP 1(i) (“Storage – The community renewable energy program tariff shall allow for co-located solar and storage.”)
6 Pacific Gas & Electric (“PG&E”), for example, could technically locate a resource in Fresno and serve customers in Humboldt County if the locational requirement under the CRE Program would be the LSE’s service area, thereby defeating the purpose of a community renewable energy program. 6 the California Energy Commission (“CEC”) to allow a resource to get RA credit as a load modifier via the LSE’s year-ahead RA forecast by virtue of reducing the LSE’s RA obligation. 7 Such coordination would preferably occur prior to contracting, to provide LSEs certainty that they would receive RA credit for resources under the program and to minimize redundant RA costs for customers.

The Joint CCAs propose a minimum project size of 500 kW and a maximum project size of 5 MW under both the IOU and CCA CRE Programs.
8 As further detailed below, the current
allocated funding amount will effectively limit the CRE Program to around 50 MW of capacity, and the limitation of the project size can ensure that more distributed resources are being built under the program to benefit more localized communities. Furthermore, it should be a primary goal of the program to site resources in areas where load is located, thereby reducing the likelihood of land availability for large resources. For those reasons, the Joint CCAs recommend a smaller maximum system size than the one proposed in the Decision.

Contrary to Southern California Edison’s (“SCE”) proposal, the Joint CCAs do not recommend that projects must be located in capacity constrained areas.9 The Joint CCAs propose 7 The Net Value Billing Tariff (“NVBT”) proposal previously included a proposal for resources as load modifiers on the CEC year-ahead RA forecast which the Joint CCAs objected to. However, those concerns related to the fact that only LSEs file year-ahead RA forecasts with the CEC, and under the NVBT proposal, the LSEs would not have held the contract with the resource developer. Under the CCA CRE Program, the LSE would be the counterparty on the resource and would, therefore, have more insight into the resource. The Joint CCA acknowledge that there would be many implementation details associated with this proposal, including coordination with the CEC and, therefore, offer this as a suggestion for conversation moving forward.
8 See D.24-05-065 at 156 (The Joint CCAs are proposing a maximum project size under the 20 MW limit set by the Decision); See also Cal. Code Regs, tit. 24, pt. 1 §10-115(a)(7) (“The community shared solar electric generation system and/or community shared battery storage system shall not be served by an individual source larger than 20 MW.”).
9 See D.24-05-065 at 79 (“Other parameters of SCE’s proposal include a maximum facility size of three megawatts, a capacity constrained site location requirement, a combine solar and storage requirement (allowing for Renewable Energy Credits), and a requirement that storage dispatch rights be provided to the contracting utility.”).
7 to offer a PPA adder to projects located in capacity constrained areas but recommend against requiring project siting in those areas. This requirement would limit project siting too much and would require IOU analyses which have been unavailable in the past.10 Finally, in accordance with Assembly Bill 2316 and the Decision, developers must demonstrate that all projects shall comply with the prevailing wage requirement, 11 and must
further demonstrate to the CEC that the proposal complies with Section 10-115 of the California Building Code.12
ii. CRE Customer Eligibility
Each LSE would enroll eligible customers in their respective CRE Programs.13 Per the Decision, all residential customers (i.e. low-income and non-low-income), as well as small commercial customers, will be eligible to enroll as subscribers to the CRE Program.14 In accordance with Assembly Bill 2316 and the Decision, the Joint CCAs propose that at least 51% of each project’s capacity under the CRE program must be subscribed by low-income customers.
15 Low-income customers are defined as individuals or households who qualify for the California Alternate Rates for Energy (“CARE”) program, Family Electric Rate Assistance (“FERA”) program, CalFresh, Supplemental Nutrition Assistance Program (“SNAP”), or the Low-income Heating Energy Assistance Program (“LIHEAP”), or reside in an underserved 10 See generally Rulemaking 21-06-017 Rulemaking to Modernize the Electric Grid for a High Distributed Energy Resources Future (“High DER Rulemaking”) including discussions about locating distributed resources in areas of grid constraint.
11 D.24-05-065 at 169, OP 1(h).
12 Id. at 168-169, OP 1(f).
13 Customers will be subscribed to a portion of a CRE project based on their previous 12-months load. If only partial or no previous load is available, customer load can be estimated. The same process is used for DAC-GT customer enrollment.
14 Technically, OP 1(d) of D.24-05-065 states that “All [emphasis added] customers will be eligible to enroll as subscribers to the tariff” (i.e. residential and non-residential customers alike). See D.24-05- 065 at 168. However, the Decision’s text at 119 implies that only residential customers, and small commercial customers, are the intended participants under the program. 15 D.24-05-065 at 169, OP 1(g).
8 community which includes low-income communities as defined in Health & Safety Code Section 39713, communities within the 25% most disadvantaged communities according to the CalEnviroScreen, and communities located on tribal lands.16 The remaining 49% of a project’s capacity is not limited to a certain customer type but, as noted in the Decision, it is recommended that this capacity would focus on enrolling non-low-income customers who rent or lease.17 Per the Decision, low-income customers would be auto-enrolled under the CRE Program.

The Joint CCAs further discuss auto-enrollment provisions in response to Question 9 in Section III below.

B. Any CRE Program Implemented by the Commission Must Take Into Account Current Funding Limitations
Some parties have raised the concern that the current funding expected to be available for the CRE Program is too limited to create an impactful program.18 The Joint CCAs agree. The Commission has noted in the Decision that it will set aside certain funding for the CRE Program, namely $33 million appropriated to the Commission by Assembly Bill 102 (2023) for community energy renewable program usage and storage-backed renewable generation programs, as well as the Environmental Protection Agency’s (“EPA”) Solar for All grant funding (collectively referred to herein as “CRE Funding”).
19 California was awarded $249,800,000 in
16 See Pub. Util. Code Section 769.3(a)(3).
17 D.24-05-065 at 118.
18 See Comments of Cypress Creek Renewables, LLC on the Proposed Decision Modifying Green Access Program Tariffs and Adopting a Community Renewable Energy Program at 12; Clean Coalition Comments on Proposed Decision Modifying Green Access Program Tariffs and Adopting a Community Renewable Energy Program at 3; Comments of The Solar Energy Industries Association on Proposed Decision Modifying Green Access Program Tariffs and Adopting a Community Renewable Energy Program at 14.
19 D.24-05-064 at 118 (citing AB 102, Budget Act of 2023, Section 244 appropriated $33 million to the Commission with additional requirements.)
9 Solar for All funding but it is not clear how much of that funding will be set aside for the CRE Program.20 If an estimated $100 million is set aside from the EPA’s Solar for All funding, in total, the CRE Program would have a statewide budget of $133 million.

While the Decision does not establish a program capacity cap, the program’s capacity is implicitly limited by the funding available for the program. As is discussed further below in Section III in response to Questions 1- 4, the CCAs are proposing that the CRE Funding would pay for two core components of the program: (1) the customer incentives (i.e. revenue share) paid to participating low-income customers and (2) the “Community Solar Adder”, an adder contributing to the overall PPA price paid to the developer. The Joint CCAs would also expect CRE Funding to cover administrative costs of the CRE Program. This is in alignment with the DAC-GT program, where ratepayer funds are used to cover (1) the bill discount paid to participating low-income customers, (2) the “above-market generation costs” of the solar (and storage) resource, and (3) administrative and marketing, education and outreach (“ME&O”) costs of the program.

Even if CRE Funding were to only cover customer incentives and the Community Solar Adder, the current funding allocation of an estimated $133 million would only allow for approximately 50 MW of statewide program capacity based on the estimated pricing assumptions that the Joint CCAs use in Table 1 below.
21 The Joint CCAs would like to highlight
20 See Solar for All Selected Applicants, available at: https://www.epa.gov/greenhouse-gas-reduction-fund/solar-all; See also D.24-05-065 at 118 fn 327 (stating that “some portion” of the funds would support the community renewable energy program).
21 In the example outlined below, the CRE Funding would cover $20/MWh for the Community Solar Adder and $2/kW-month for the Community Storage Adder for a blended rate of $36.44/MWh. The CRE Funding would also cover $52.52/MWh for the CRE solar + storage Incentive Rate for 50% of customers (only low-income) leading to total costs of $62.7/MWh. $133 million in funding can cover around 106,000MWh annually (over a 20-year contract period), and if one assumes an even split of MWhs between the solar and the storage resource, the CRE Funding could cover around 20MW in solar and 36MW in storage resource for a combined program capacity of 56MW. 10 that such a limited program cap (and estimated funding amount) may be insufficient to incentivize the administrative effort necessary to develop a new community renewable energy program in California. As noted above, the Joint CCAs support the development of local FTM DERs but also want to caution that adequate funding must be available to make the program successful (if not feasible). Commissioner Houck also acknowledged the current funding limitations for the CRE Program and the risks it poses to the success of the program in her dissent to the recent Decision.22 The Joint CCAs strongly recommend that the Commission take these funding limitations into consideration when further developing the CRE program and consider potential avenues for additional funding that may be available for this program.

III. RESPONSES TO RULING QUESTIONS: NEW COMMUNITY RENEWABLE

ENERGY PROGRAM
A. Revenue Share and Bill Credits

1. The new community renewable energy program is designed to deliver value through two streams of funding: (i) the stable but moderately adjusting compensation from wholesale tariffs and (ii) the external, nonratepayer, funding or “adder” that is managed through investor-owned utility (Utility) balancing accounts. How should these streams of funding be applied to provide both developer compensation and subscriber savings or revenue share (i.e., percentage split of total revenue from a project between the developer or generator account and benefiting or subscriber accounts)? The Joint CCAs make the following proposal regarding the structure of the developer compensation and the subscriber’s “incentive”
23 for the CRE Program (including IOU and CCA
tariffs). These proposals are based on SCE’s proposal provided in SCE’s Opening Comments to the Ruling Setting Aside Submission of the Record to Seek Comments on Aspects of Net Value 22 See Concurrence and Dissent of Commissioner Darcie L. Houck as to the Decision Modifying Green Access Program Tariffs and Adopting a Community Renewable Energy Program. 23 As described above, the Joint CCAs call the subscriber’s “revenue share” an “incentive” as it more appropriately describes the form of payment the customer receives. Following SCE’s proposal, the customer does not receive a share of the projects revenue (which would be CAISO revenues), but instead the customer incentive is calculated as a percentage of the PPA price. 11 Benefit Tariff Proposal, dated November 6, 2024 , as well as the requirements of the Decision with slight proposed modifications.
i. Developer Compensation
The Joint CCAs agree with SCE’s proposal that developers be paid based on the project’s PPA price.24 Importantly, the PPA would braid several different value streams together to ensure that the developers are encouraged to develop local, community-based solar, or solar plus storage, projects. The Joint CCAs propose that the PPA price offered under the CRE Program be comprised of three core elements: (i) a base payment, (ii) a Community Solar Adder, and (iii) a Grid Capacity Adder. Additionally, for the CCA CRE Programs specifically, an individual CCA has the discretion to add a fourth element, a “Community Goals Adder.” The following describes each of the proposed PPA elements in more detail.

Base Payment
The base payment should be consistent across IOU and CCA CRE projects, and should be set at the respective IOU’s PURPA avoided cost rate, as determined by the Commission through an administrative process.
25 As noted in the Decision, the use of PURPA avoided costs to compensate generation resources will not result in a cost shift to non-participating ratepayers.26 Community Solar Adder
The Community Solar Adder should also be consistent across all IOU and CCA CRE projects and would be paid for through CRE Funding.27 The purpose of this adder would be to 24 See D.24-05-065 at 79.
25 See e.g. Resolution E-5323 (Adoption of 2024 updated administratively set fixed avoided-cost rates for the ReMAT program pursuant to D.20-10-005); see also D.20-05-006, OP 1 and OP 2 (determining the calculation of energy and capacity prices under the standard offer contract program). 26 D.24-05-065 at 124.
27 As noted in section II.B above, “CRE Funding” is defined as the $33 million appropriated to the Commission by Assembly Bill 102 (2023) for community energy renewable program usage and storage- 12 encourage the development of projects in areas where the load is located and to develop true community-based renewable energy projects (i.e. projects are located “close” to where customers are located).28 This value would be similar to the “above market generation costs” under the DAC-GT program, but unlike the DAC-GT above market generation costs (which vary by project), would be set at the same level across all CRE projects.

The Joint CCAs propose that the Commission convene a working group to further discuss the appropriate value of the Community Solar Adder. For example, one issue that should be investigated is whether it would appropriate to provide local resources in load pockets with additional value for the avoided costs of using the transmission system. It should also be investigated further if it is appropriate to derive the Community Solar Adder from other small-scale renewable energy feed-in-tariffs (“FITs”) like the ReMAT. Another option is to consider historic costs for local capacity as an adder for resources that can count for RA. The question of how local FTM DERs can be valued has been an issue of much discussion in this instant proceeding and the Joint CCAs believe that a Commission-organized working group would provide the appropriate venue for developing an appropriate valuation methodology.

Grid Capacity Adder
The Grid Capacity Adder would be included for projects that are located in a capacity constrained area and would be paid for by the IOUs. The IOUs should make a proposal on how to develop the Grid Capacity Adder based on their experience under the Distribution Investment Deferral Framework (“DIDF”) solicitation process.29 In the past, the IOUs have recommended backed renewable generation programs, as well as the Environmental Protection Agency’s (“EPA”) Solar for All grant funding.
28 See a proposed definition for proximity between customers and projects in Section II.A.i. above. 29 To date, the DIDF solicitations have largely been unsuccessful. It is currently being discussed in the Commission’s High DER Rulemaking (R.21-06-017) if the DIDF solicitations should be terminated. 13 that resources would have to participate in designated solicitation processes such as the DIDF to gain access to additional locational benefits and value. For example, for a DAC-GT resource to receive locational value, it would have to participate (and be selected) in both the DAC-GT and the DIDF solicitations. This is a cumbersome and impractical process for any developer that has never been successful to date. To give projects in grid constrained areas more timely and direct access to additional locational benefits, the Joint CCAs recommend that the utilities propose a methodology to provide a “Grid Capacity Adder” under the CRE Program itself.

Community Goals Adder (or “CCA Adder”)
The Community Goals Adder would be specific to the CCA CRE Program and would be paid for by the participating CCA. Under this proposal, a CCA can choose to adjust the PPA price to align with the CCAs’ avoided procurement costs and/or to support specific goals and interests of the CCA and its community. For example, a CCA is likely to have avoided procurement costs that differ from their respective IOU and could therefore choose to modify the value to a developer beyond the IOU’s PURPA avoided cost (which is the base payment under the CRE Program). Many CCAs also have specific goals and interests in their community (e.g. rehabilitation of brownfields, reduction of local air quality impacts due to fossil-fuel power stations, or development of local projects in disadvantaged communities (“DACs”)) and may therefore be willing to provide additional value to the developer under the CRE Program. The Community Goals Adder would be different for each CCA, with each participating CCA proposing the value of the adder in their respective SOC documents.

Any discussions in the High DER Rulemaking should inform the Grid Capacity Adder proposal the IOUs make for the CRE Program.
14 The Joint CCAs provide a summary of the PPA elements, with example pricing, in Table 1 below.30 The Joint CCAs recommend that a separate pricing structure is developed for solar and storage resources based on the service they provide, rather than a blended rate.31 This provides more flexibility to developers and allows for co-located (rather than just hybrid) solar and storage resources as provided for in the Decision.32 Table 1: Example of Proposed PPA Structure
PPA Element Solar
($/MWh)
Storage
($/kW-month)
Cost Recovered by
Base payment $30 $15 Participating LSE
Community Solar Adder $20 $2 CRE Funding
Grid Capacity Adder $20 $2 IOU
Community Goals Adder $20 $2 CCA
TOTAL $90 $21
Finally, the Joint CCAs recommend that the PPA pricing (and associated adders) could be adjusted based on industry responses to CRE solicitations, similar to the ReMAT program.

For example, if few (or no) responses are received to a CRE solicitation, the Community Solar Adder could increase by a certain percentage to further encourage participation in the solicitation. After a successful CRE solicitation, the adders could be decreased for the next tranche of the CRE Program solicitation.
ii. Participant Revenue Share (or “Customer Incentive”) Per the Decision, all residential customers, as well as small commercial customers, are eligible to enroll as subscribers to the CRE Program. However, the Decision only adopts a minimum revenue share (or customer incentive) for low-income subscribers and declines to 30 Note that pricing is approximated and does not necessarily reflect actual market costs. 31 The Joint CCAs note that a blended rate could be calculated by the participating program administrators for the purposes of calculating the subscriber incentives as further described below in response to Question 2.
32 D.24-05-065 at 169, OP 1(i). Co-located resources typically have separate prices for solar and storage resources while hybrid solar and storage resources use a blended rate. 15 specify a minimum revenue share for non-low-income (i.e. “general market” subscribers) as they will not receive a subsidy through external funding.33
The Joint CCAs support SCE’s proposal that the program should provide a flat monetary credit based on a percentage of the contracted project compensation (i.e. the PPA price) for low-income subscribers. General market subscribers would not receive an incentive but would also not have to pay for the above-market generation costs incurred by the resources under the program. In other words, all subscribing customers remain on their otherwise applicable tariff (“OAT”) when enrolling under the CRE Program. Low-income customers only will then receive an annual bill credit based on a percentage of the PPA price. The Joint CCAs discuss the level of incentives for low-income customers in more detail in response to Question 2 below.

2. Decision (D.)24-05-065 states, “The Commission finds that a minimum 20 percent revenue share for low-income subscribers is reasonable and provides protection for subscribers. However, the record of this proceeding does not contain adequate details on a specific percentage credit.” What should the revenue share for low-income subscribers be and how should it be calculated? Comments should consider that some external funding types may have certain conditions to ensure the funding benefits low-income customers.

As noted above in response to Question 1, the Joint CCAs support SCE’s proposal to provide low-income subscribers with an incentive based on 20% of the PPA price provided under the specific CRE project that the customer subscribes to. In a simple example, if a customer were to subscribe to a solar-only project that has a PPA price of $90/MWh, the customer incentive rate would be set at $18/MWh (i.e., the “CRE Incentive Rate”). The customer incentive credit would then be calculated during an annual “true-up” process by multiplying the customer’s usage over the previous 12 months with the CRE Incentive Rate. Under this example, a customer with a 6 MWh annual usage would receive an annual bill credit of $108. 33 Id. at 120
16 While this calculation is relatively straightforward for solar only projects, it is a bit more complex to calculate a 20% share for PPA prices that are composed of both an energy price ($/MWh) for the solar resource and a capacity price ($/kW-month) for the storage resource.34 Under the example provided in response to Question 1 above, the solar resource would be paid $90/MWh and the storage system $21/kW-month. If one were to convert the storage system’s capacity price into an energy price to create a blended $/MWh rate, and then take 20% of the blended PPA price, the customer would receive a CRE Incentive Rate of $52.6/MWh.35 In this case, a customer with a 6 MWh annual usage would receive an annual bill credit of $315.60, a significant increase compared to the annual bill credit of $108 for a solar resource only. For comparison purposes, under MCE’s DAC-GT program, low-income customers received an average of $450 in bill credits in 2023 (calculated as a 20% bill discount off the electric portion of their bill).
36 Effectively, low-income customers subscribed to a solar-only CRE project would receive only about one third of the annual incentive that DAC-GT participants receive (under the assumptions of the above example). However, as CRE Funding is limited, this would allow for more customers to be subscribed under the program and to provide an incentive to a larger number of low-income customers. This would also help meet AB 2316’s statutory objective to “promote robust participation by low-income customers.” 37 34 The Joint CCAs maintain that the developers should be paid two separate prices for their solar and storage resources to enable the participation of co-located resources. 35 The blended PPA rate is calculated as follows: a 4-hour, 1MW battery would generate 1460 MWhs of energy annually and would get paid $252,000 per year, which comes to an $/MWh rate of $173/MWh. The blended PPA price would be $263/MWh ($90/MWh for the solar resource). 20% of the blended PPA rate amounts to a CRE Incentive Rate of $52.60. 36 See MCE Advice Letter 79-E.
37 Pub. Util. Code Section 769.3(b)(1)(3).
17 Low-income customers subscribed to a solar and storage CRE project would receive approximately the same annual incentive that DAC-GT participants receive. While this may generally be a desirable outcome, the Joint CCAs would like to note that CRE Funding will be expended very quickly on a limited number of customers due to the high customer incentive costs. The Joint CCAs elaborate on the challenges regarding limited CRE Funding in Section II.B above.

In summary, when implementing the CRE Program, the Commission must find a balance between providing reasonable incentives to low-income customers while also reaching as many customers as possible. The Joint CCAs believe that the proposed rate structure outlined above is a reasonable approximation of what the CRE Incentive Rate could look like. However, the Joint CCAs are also open to discussing further modifications to the methodology with stakeholders to strike the right balance between the level of low-income customer incentives and the number of program participants.

3. D.24-05-065 states “With respect to bill credits, the Commission finds the [Southern California Edison (SCE)] proposal to use the simplified Shared Savings Model using balancing accounts to provide a flat monetary credit on subscriber bills is reasonable…The Commission finds that a minimum 20 percent revenue share for low-income subscribers is reasonable and provides protection for subscribers. However, the record of this proceeding does not contain adequate details on a specific percentage credit. A future ruling in this proceeding will allow for additional record development. The Commission also declines to specify a minimum revenue share for -non-low-income-subscribers as they will not receive a subsidy through external funding.” Propose, in detail, how a low-income and non-low-income bill credit should be applied, including billing presentment.

As noted above in response to Question 1, the Joint CCAs propose that non-low-income subscribers would not receive an incentive and would remain on their OAT. Low-income customers would receive an incentive calculated as 20% of the PPA price, as further detailed in response to Question 2. Additionally, while the Joint CCAs currently propose that non-low- 18 income subscribers would not receive incentives, to the extent the Commission determines that general market subscribers are required to receive a percentage of the revenue share under Public Utilities Code Section 769.3(c)(5), the Joint CCAs would support an incentive of up to 10% of the PPA price for non-low-income customers (calculated as described above in response to Question 2). However, as this incentive would not be provided through the currently available external funding, it is unclear how the costs for this incentive would be covered.38 The Joint CCAs further propose that for low-income customers, the incentive would be applied directly to the customers’ generation portion of their electric bills after the annual true-up process. As the customer incentive would be covered by CRE Funding, both IOUs and CCAs would seek cost recovery for the bill credit from the IOU balancing account tracking the CRE Funding. The Joint CCAs propose that this process follows the same process as the DAC-GT program. Namely, a CCA participating in the CRE Program would submit an annual budget advice letter to the Commission and the IOUs would distribute funding to the CCAs in advance.

The CRE Program budgets would then be trued-up on an annual basis.

B. Non-Ratepayer-Funded Adder

4. What should be the developer incentive or adder per project and how should it be calculated? Potential funding sources include the Environmental Protection Agency’s (EPA) Solar for All grant funding, General Funds allocated to the Commission, and others to be determined. a. Should the incentives for developers be based on dollars per watt, dollars per kilowatt-hour, a lump sum, or some other scheme? Explain why.

As noted above in response to Question 1, the Joint CCAs propose that the developer be compensated based on the PPA price offered by the LSE in its SOC. Solar resources would be paid a $/MWh price for the energy produced by the system. Solar plus storage resources would 38 See D.24-05-065 (noting that non-low-income subscribers will not receive a subsidy through external funding).
19 offer a distinct pricing structure for the solar and the storage resource (where solar would be paid a $/MWh price for the energy produced and storage would be paid a $/kW-month price for the capacity provided by the system). Basing developer compensation on a PPA price or storage rate is the standard mechanism for LSEs to procure FTM resources and the simplest and most efficient way to structure developer compensation under the CRE Program. b. What process should the Commission use for determining the incentive or adder? Should the Commission set the incentive or adder price administratively or should it require the utilities to use a method such as a reverse auction that would introduce price discovery? If you recommend a price discovery method, specify the method you propose and the justification for using that method.

As further discussed in response to Question 1 above, the Joint CCAs propose that the Commission establish a working group process to discuss the valuation of the Community Solar Adder. The Joint CCAs also provide proposals for how the Grid Capacity Adder and Community Goals Adder should be set in response to Question 1(a). c. Should the incentive or adder be based on a minimum dollar amount per customer or a minimum percentage of project revenue share? Should the incentive or adder increase if more low income customers are signed up beyond the 51 percent per project minimum threshold? As noted above in response to Question 1, the Joint CCAs recommend that the developer be compensated under a standard PPA, not based on a minimum revenue share or dollar per customer amount. Developers should also not receive an increased adder or incentive based on the number of low-income customers subscribed in the CRE Program, especially as developers will not be involved in the recruitment of subscribing customers under the CCA proposal (as noted in Section II.A.ii, LSEs would be responsible for enrolling eligible customers, not developers).
20 d. What other non-monetary incentives or assistance could utilities or Community Choice Aggregators (CCAs) provide to community renewable energy program projects and developers?
See a detailed description of the “Grid Capacity Adder” (provided by the IOUs) and the “Community Goals Adder” (provided by CCAs) above in response to Question 1.

C. Federal Incentives

5. Some CCAs who administer the Disadvantaged Communities Green Tariff (DAC-GT) have successfully negotiated lower Power Purchase Agreement contract prices with selected developers if a project receives the federal Investment Tax Credit (ITC) Low-Income Community Bonus Credit. Similarly, the Solar on Multifamily Affordable Housing program also set a precedent for aligning incentives, such as the federal ITC, with incentives provided for the installation of solar. Should the new community renewable energy program follow a similar process for leveraging the federal incentives available in the Inflation Reduction Act including the Low-Income Community Bonus Credit and other new and available tax credits?
As the Joint CCAs have previously noted in this proceeding, it is important for renewable energy projects to take advantage of federal tax credits.39 However, it is common practice for project developers to incorporate the Investment Tax Credit (“ITC”) and similar benefits into PPA pricing. The Joint CCAs do not believe it is necessary to incorporate any requirement within the CRE program to encourage these incentives.

D. Disbursal of Non-Ratepayer Funds

6. D.24-05-065 states “Utilities would have the role of fiscal agents and apply monetary credits to the generation, i.e., benefiting, and customer, i.e., subscriber, accounts. The Commission finds that it is reasonable to direct Utilities to establish a balancing account to track the subscriber revenue shares and distribute the appropriate shares through the bill credit. Further, changes to the credits based on facility performance and credit distribution can be easily updated through an annual trueup process.” How should the external funding be disbursed to the projects and participating customers of Utilities and CCAs?
39 See Reply Brief of the Joint Community Choice Aggregators and City and County of San Francisco at 14.
21 As described in the Decision, the IOUs would create balancing accounts for CRE Funding which is expected to be the $33 million in general funds and a to-be-determined amount of the EPA’s Solar for All Funding. Under the CCAs’ proposal, the IOUs would also create another sub-account under the same balancing account to track and disburse the IOU-provided “Grid Capacity Adder”.

Similar to the DAC-GT program, the Joint CCAs propose that both IOUs and CCAs would submit an annual budget advice letter forecasting the costs for the CRE Program and specifying which costs are recovered from which balancing sub-account (CRE Funding vs. Grid Capacity Adder). The IOUs would provide the CCAs with the forecasted funding for the CCA CRE Program in anticipation of expenses to be incurred. The CRE Program budgets would then be trued-up on an annual basis.

E. Treatment of Utility Implementation and Administrative Costs

7. What funding source should be used to pay for start-up costs and program administration and what process should be used for cost recovery? This may include costs associated with billing system updates, the customer enrollment process buildout, ongoing subscription management and development of a new solar and storage contract (if needed).

The Joint CCAs note that existing community solar programs, such as the DAC-GT program, cover administrative costs with ratepayer funds which cover program start-up costs such as billing system updates, the customer enrollment process etc. For more details, see the Joint CCAs’ response to Question 22 below. These administrative costs were not accounted for in the Decision for the new CRE Program. However, such costs are necessary to implement a successful program. As noted above in Section II.B., the Joint CCAs are concerned that the currently allocated external CRE Funding can only support customer incentives, above-market generation costs, and administrative costs for a small program capacity. Therefore, the Joint 22 CCAs strongly recommend that other funding sources be identified to make this program more viable.

F. CCA Participation

8. D.24-05-065 states “As CCAs are permitted to participate in the new community renewable energy program, the foundational tariffs will need to be revised to accommodate this participation. At this time, the record does not contain the specifics for CCA participation.”
a. What process should be employed to enable CCA participation in the community renewable energy program? This would include discussion of how CCAs must notify the Commission of their participation in accordance with Pub. Util. Code Section 769.3(b)(2)(B) and the process for CCAs to access external funds?
Pursuant to Public Utilities Code Section 769.3(b)(2)(B), if the Commission establishes a new community renewable energy program, each CCA “shall notify whether it will participate in the program, within 180 days of the establishment [emphasis added] of the program.” 40 As
evidenced by the ALJ Ruling, there are still many remaining questions regarding the implementation of a CRE Program. Further, the Decision notes that the Commission intends to address CRE Program implementation issues through a subsequent implementation decision.41 CCAs will not be able to properly determine whether to participate in the new program until most of the implementation questions and issues have been resolved. Therefore, the Joint CCAs recommend that the CRE Program be determined “established” for purposes of the 180 day deadline when the second decision is issued determining the details of the CRE Program. 42 Upon
the issuance of the second decision, CCAs that are interested in offering the CRE Program would then have 180 days to submit their own CRE Program tariffs (i.e., the SOCs), as well as additional program implementation details, to the Commission via a Tier 2 Advice Letter. This 40 Pub. Util. Code § 769.3(b)(2)(B).
41 D.24-05-065 at 123.
42 See id. at 123, 147 (noting that a second proposed decision will be issued to finalize outstanding implementation issues associated with the new program). 23 process would both (1) notify the Commission of the CCA’s intent to participate in the program and (2) provide the necessary tariff and implementation details for Commission consideration of the CCA’s participation in the CRE Program. Upon approval of the Tier 2 AL, the CCA would make the CRE SOC publicly available and prepare for program launch. This process follows the example of the rollout of the DAC-GT programs offered by CCAs. b. Which CCA tariffs should be eligible for the program? The Joint CCAs propose the creation of new CCA SOCs as foundational tariffs for the CRE Program. See more details about the contract structure in Section II.A.i above. Furthermore, each CCA will share the specific details of their SOC (e.g. the details about the individual CCA Community Goals Adder) when submitting the necessary tariff documents to the Commission in the Tier 2 AL described in response to Question 8(a) above.

G. Enrollment

10. Should Utility-facilitated or CCA-facilitated auto-enrollment be the only enrollment pathway for low-income customers in DAC-GT and the new community renewable energy program? What other enrollment options are available? What are the benefits or drawbacks of either approach? Comments should consider potential administrative cost, alignment with other low-income programs like the California Alternate Rates for Energy (CARE) program, compatibility with Title 24, the customer enrollment experience, ease of customer understanding billing/crediting, and consumer protections.

The Joint CCAs understand that the Decision requires automatic enrollment for the CRE Program.43 The Decision further specifies that low-income customers enrolled in the IOU or CCA Arrearage Management Program should be prioritized for automatic enrollment, followed by all other low-income customers who subscribe to the tariff.44 The Joint CCAs propose that 43 D.24-05-065 at 119.
44 Id.
24 non-low-income customers would not need to be auto-enrolled and would, instead, voluntarily subscribe to the CRE Program.

The Decision follows the auto-enrollment approach utilized in D.20-07-008 and Resolution E-5124 for the modified DAC-GT program.45 In Resolution E-5124, the Commission recognized that CCAs designing their own auto-enrollment criteria, instead of using specific statewide criteria, could prevent program implementation delays.46 Pursuant to D.20-07-00847 and Resolution E-5124,
48 CCA program administrators have created auto-enrollment criteria and also offered self-enrollment options for eligible customers that indicate interest in joining the DAC-GT program voluntarily. The Joint CCAs support the existing auto-enrollment process for the modified DAC-GT program and maintaining self-enrollment opportunities for customers otherwise eligible under a CCA’s auto-enrollment criteria.

11. If you recommend auto-enrollment, describe the criteria that should be used for i) determining which customers would be auto-enrolled in the community renewable energy program and ii) ensuring that customers aren’t enrolled in more than one program (i.e. community renewable energy program and DAC-GT). Additionally, explain which program (i.e. community renewable energy program and DAC-GT) would low-income customers be enrolled in first? The Joint CCAs note that there are different eligibility requirements under the CRE Program and the DAC-GT program. The DAC-GT program is available to low-income residents who reside in DACs and are eligible for either the CARE or FERA programs.49 Low-income 45 Id. at 133.
46 Resolution E-5124 at 19 (providing “that CCAs design their auto-enrollment criteria in such a way as to prevent issues and further program implementation delays from occurring, while still retaining alignment with D.20-07-008”).
47 D.20-07-008 at 14, OP 2.
48 Resolution E-5124 at 19, 31.
49 See Resolution E-5212.
25 customers eligible for the CRE Program as defined by Assembly Bill 2316 is a much broader group.50
Acknowledging the discrepancy in the eligible customers between the two programs, the Joint CCAs believe that low-income customers and the customers who are at the highest risk of being disconnected should be enrolled in whichever program provides the highest benefit and/or the largest discount on their monthly bills that they may be eligible for. Based on the Joint CCAs’ current understanding of the new CRE Program, the Joint CCAs believe the DAC-GT program would likely provide the higher benefit to low-income customers as the program guarantees that customers will receive 20% off their electric bills. As such, the Joint CCAs propose that DAC-GT eligible customers first be enrolled in the DAC-GT program with remaining customers automatically enrolled in the CRE Program (up to the program cap). However, the final determination for the customer incentive under the CRE Program has not yet been made. It will be important to consider party comments in response to Question 1 of the Ruling and the Commission’s ultimate determination on this issue prior to making a final determination on which program customers should be enrolled in first.

IV. RESPONSES TO RULING QUESTIONS: MODIFIED DISADVANTAGED

COMMUNITIES GREEN TARIFF PROGRAM

12. Determining the prior year spending for multiple DAC-GT program administrators on is a challenging task which requires review of multiple annual budget advice letters. Explain whether you think it would be simpler to have one of the three investor-owned utilities submit an annual report on behalf of all DAC-GT administrators showing historical spending each year in the first quarter?
It is unclear from the question whether an annual report submitted by the IOUs on behalf of all the DAC-GT program administrators would be in lieu of the annual budget advice letters 50 See Pub. Util. Code Section 769.3(a)(3).
26 (“ABALs”), or in addition to the ABALs. The Decision clarifies that the submission date of the ABALs is moved from February 1 to April 1 of each year,51 however the instant question seems to suggest that an annual reporting process would be “simpler” than the submission of the ABALs. In general, the Joint CCAs do not object to an annual report containing public information providing details on the prior years’spending for the DAC-GT program. However, it is not practical for an annual report to be submitted by one of the IOUs that either (i) requires the coordination and transfer of confidential data to the IOUs for submission or (ii) prevents each program administrator’s budget from being independently reviewed by the Commission as is the current process through the ABALs.

First, it would be burdensome to coordinate the transfer of confidential data to the IOUs for submission in an annual report replacing the ABALs. Second, in the original decision, each CCA’s administrative and marketing costs must be approved by the Commission as those costs are capped.52 This submission and approval process requires a Tier 2 AL submission from each program administrator.
53 Due to this, the Joint CCAs understand that each ABAL must be reviewed individually to assess the cost caps, and a joint submission by one IOU would be unnecessary and would cause confusion should one program administrator’s costs need to be reevaluated by the Commission. Therefore, the Joint CCAs would object to an IOU reporting process that replaced the ABAL submissions.

Additionally, while the Joint CCAs would not have an objection to an annual report submitted by an IOU that contains public information to facilitate stakeholder review of relevant spending for the DAC-GT program, any annual report should be submitted in the second, or even 51 D.24-05-065 at 134.
52 See Resolution E-4999 (establishing a 10 percent cost cap for program administration and 4 percent cost cap for marketing, education, and outreach). 53 See id. at 68, OP 4.
27 third, quarter of the year to ensure the information being provided is accurate. Specifically, a budget report should not be posted until after the review and disposition of the initial program administrator ABALs. As noted in the Decision, the ABAL submission deadline was moved from February 1 to April 1 to allow for improved accuracy in tracking costs. 54 Requiring submission
of an annual report in the first quarter of each year would negate this improvement and result in inaccurate spending data.

13. In D.04-12-048 of the Long-Term Procurement Planning Proceeding, the Commission required Utilities to hire an Independent Evaluator to monitor competitive solicitations that involve affiliate transactions, Utility-built or Utility turnkey bidders. Subsequently, D.06-05-039 required an Independent Evaluator to also monitor all Renewables Portfolio Standard program solicitations to separately evaluate and report on a Utility’s entire solicitation, evaluation and selection process for this and all future solicitations. The Independent Evaluator serves as an independent check on final selections, by ensuring solicitations are conducted in an open, fair, and transparent process.

Should the Independent Evaluator for each Utility be required to submit a report for all Utility DAC-GT procurements, whether or not a Request For Offer results in a selected bid?
The Joint CCAs do not take a position on this question as the Independent Evaluator required by D.06-05-039 applies only to the IOUs.

V. RESPONSES TO RULING QUESTIONS: MODIFIED AND LEGACY GREEN

TARIFF AND SHARED RENEWABLES
A. Incremental Renewable Procurement – All Parties Respond D.24-05-065 adopts the Utilities’ proposal to bundle any future solicitations for new resources to meet modified green tariff demand with the same procurement activities it will undertake to meet its long-term planning goals to ensure least cost best-fit procurement. The Decision requires Utilities to each submit a Tier 2 Advice Letter updating their existing Green Access Program tariffs according to the directives of the decision, including details on how their programs will result in incremental new renewable energy being purchased.

17. Describe how additional renewable procurement should be accomplished, citing key dependencies to an approved Integrated Resource Plan Decision and process.
54 D.24-05-065 at 134.
28 a. How would a participant be assured that these resources are from incremental renewable resources?
As noted in Resolution E-4999, the purpose of creating the DAC-GT program was to promote development of new renewable energy projects in DACs.55 Pursuant to the DAC-GT program implementation Resolutions, DAC-GT program administrators must submit executed PPAs no later than 180 days following notification of selected bidders of solicitations. This process has demonstrated that the projects used to serve the DAC-GT program are new renewable energy projects. The modified DAC-GT program will continue to submit PPAs to the Commission through an Advice Letter process. The Joint CCAs believe these PPA submissions should provide sufficient detail that the proposed projects are new incremental projects.

Additionally, any projects will be included in the program administrators’ Integrated Resource Plans which are also reviewed by the Commission. The Joint CCAs believe any dependencies created between the Integrated Resource Planning process and the DAC-GT or new CRE Programs would be unnecessary and overly complicated.

VI. RESPONSES TO RULING QUESTIONS: ALL CALIFORNIA RENEWABLES

PORTFOLIO PROGRAMS

22. For the legacy Green Tariff, modified Green Tariff, and Disadvantaged Communities Green Tariff programs, provide a breakdown of budget line items by category and program, using the same categories used in Exhibit CA-01 Appendix B. Are there other cost categories, such as a regulatory compliance line item, that should be included in the programs’ reporting? The Joint CCAs support a budget line item breakdown consisting of four main categories:
(i) above market generation costs, (ii) bill discount, (iii) program administration, and (iv) ME&O as used in Exhibit CA-01 Appendix B. While the Joint CCAs believe these main categories sufficiently make up the programs’ reporting, some program administrators provide additional 55 Resolution E-4999 at 23.
29 detail on cost breakdowns within these categories. For example, “program administration” often includes the following sub-categories: (i) program management, (ii) information technology (“IT”), (iii) billing operations, (iv) regulatory compliance, and (v) procurement. Additionally, ME&O costs would include (i) labor costs, and (ii) outreach and material costs. If budget line items are broken down further from the main categories listed above and included in Exhibit CA-01, the Joint CCAs request that, at a minimum, these subcategories also be included.

VII. CONCLUSION
The Joint CCAs thank the Commission for its consideration of the matters set forth in these comments.

July 10, 2024 Respectfully Submitted,
/s/ Brittany Iles
Brittany Iles
BRAUN BLAISING & WYNNE, P.C.
555 Capitol Mall, Suite 570
Sacramento, California 95814
Telephone: (916) 326-5812
E-mail: [email protected]
Attorney for the
Joint Community Choice Aggregators and
City and County of San Francisco

BEFORE THE PUBLIC UTILITIES COMMISSION

A.22-05-022
And Related Matters. A.22-05-023
A.22-05-024

OPENING COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS

A.22-05-022
And Related Matters. A.22-05-023
A.22-05-024

OPENING COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS

The Joint CCAs further discuss auto-enrollment provisions in response to Question 9 in Section III below.

III. RESPONSES TO RULING QUESTIONS: NEW COMMUNITY RENEWABLE

ENERGY PROGRAM
A. Revenue Share and Bill Credits

The CRE Program budgets would then be trued-up on an annual basis.

B. Non-Ratepayer-Funded Adder

C. Federal Incentives

D. Disbursal of Non-Ratepayer Funds

E. Treatment of Utility Implementation and Administrative Costs

F. CCA Participation

G. Enrollment

IV. RESPONSES TO RULING QUESTIONS: MODIFIED DISADVANTAGED

COMMUNITIES GREEN TARIFF PROGRAM

V. RESPONSES TO RULING QUESTIONS: MODIFIED AND LEGACY GREEN

VI. RESPONSES TO RULING QUESTIONS: ALL CALIFORNIA RENEWABLES

PORTFOLIO PROGRAMS

VII. CONCLUSION
The Joint CCAs thank the Commission for its consideration of the matters set forth in these comments.

ADVANCING LOCAL ENERGY CHOICE
July 17, 2024
VIA ELECTRONIC MAIL: [email protected]
Public Utilities Commission of the State of California
Energy Division
Attention: Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, CA 94102
dvice Letter 16-E dvice Letter 50-E
pple Valley Choice Energy va Community Energy
dvice Letter 10-E dvice Letter 30-E
dvice Letter 11-E dvice Letter 7-E
ese1·t Community Energy • For Palmdale's
dent Choice
dvice Letter 80-E Letter 10-E
ounty Power
dvice Letter 25-E tter 20-E
y
E
·age Energy
er 23-E
San Jacinto Power
dvice Letter 33-E
Silicon Valle Clean Ener
ioneer Community Energy
clvice Letter 22-E
¥oocl Coast Energy
tter 36-E
San Jose Clean Ener
dvice Letter 24-E
Sonoma Clean Power
dvice Letter 42-E
Letter 31-E
dvice Letter 30-E
dvice Letter 36-E
eninsula Clean Energy
dvice Letter 11-E
dvice Letter 22-E
an Diego Community Power
dvice Letter 7-E
anta Barbara Clean Ener
clvice Letter 19-E
RE: Joint CCAs' New CCA Registration Requirements Tier 2 Advice Letter Pursuant to Decision (D.) 24-04-009
The California Community Choice Association (CalCCA) submits this Tier 2 Advice Letter (Advice Letter) on behalf of Apple Valley Choice Energy, Ava Community Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance of Southern California, CleanPowerSF, Dese1i Community Energy, Energy For Palmdale's fudependent Choice, Lancaster Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera funovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Auth01ity, San Diego Community Power, San Jacinto Power, San Jose Clean Energy, Santa Barbara Clean Energy, CalCCA / Joint CCAs T2 Advice Letter
July 17, 2024
Page2
Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy (collectively, the Joint CCAs). 1 This Advice Letter is submitted pursuant to Ordering Paragraph (OP) 5 ofD.24- 04-0092 (the Decision). The Joint CCAs request the California Public Utilities Commission's (Commission) approval of this Advice Letter documenting new community choice aggregator (CCA) registration requirements.

I. TIER DESIGNATION
The Joint CCAs hereby submit this Advice Letter with a Tier 2 designation.

II. EFFECTIVE DATE
This Tier 2 Advice Letter will become effective upon disposition of this Advice Letter.

III. BACKGROUND
In D.05-12-0413 and Resolution E-49074, the Commission requires new CCAs to submit an Implementation Plan. The Implementation Plan provides info1mation regarding rate setting, organizational strncture, operations, funding, and third-pa1iy power suppliers, as set forth in Public Utilities Code section 366.2. Within the provider of last reso1t (POLR) proceeding Rulemaking (R.) 21-03-011, CalCCA proposed the Commission enhance the implementation planning process with four requirements that would apply to newly fo1ming CCAs: (1) submission of a feasibility study, if available, and pro fonna financial statement with the Implementation Plan; (2) establishment of aI111ual assumptions to be included in the pro fmma financial statement; (3) establishment of milestones for c1itical implementation action and review progress; and ( 4) submission of an updated pro fmma financial statement six months prior to launch. These requirements would apply to newly fanning CCAs only, not existing CCAs expanding their service tenitories.

OP 5 of D.24-04-009 directs the CCAs to file a joint Tier 2 advice letter within 90 days of the Decision's effective date to further develop the additional registration requirements proposed by CalCCA. The Decision states, "Specifically, the advice letter filing should include an explanation of the type of annual assumptions that might be included in the pro fo1ma financial statement, as well as example milestones for critical CCA implementation."5 As the Commission has previously acknowledged, Assembly Bill 117 (Migden, 2001) does not provide the Commission authmity to approve or reject a CCA's implementation plan or to dece1tify The Joint CCAs have provided CalCCA with authority to submit this Advice Letter on their behalf. 2 D.24-04-009, Decision Implementing Senate Bill 520 Regarding Standards for Provider of Last Resort, R.21-03-011 (Apr. 18, 2024):
https://docs.cpuc.ca.gov/PublishedDocs/Published/GO0O/M529/K986/529986322.PDF. 3 D.05-12-041, Decision Resolving Phase 2 Issues on Implementation of Community Choice Aggregation Program and Related Matters, R.03-10-003 (Dec. 16, 2005):
https://docs.cpuc.ca. gov/PublishedDocs/WORD PDF /FINAL DECISION/52127 .PDF, 4 Resolution E-4907, Registration Process for Community Choice Aggregators (Feb. 9, 2018):
https:/ /docs.cpuc .ca. gov/PublishedDocs/Pl1blished/GO00/M2 l 0/K0 16/210016662.PDF. 5 D.24-04-009 at 86.

CalCCA / Joint CCAs T2 Advice Letter
July 17, 2024

Page 3 ends

a CCA. Rather its role is to ensure that CCA Implementation Plans are consistent with utility tariffs and Commission mies designed to safeguard customers. 6 In recognition of the Commission's need to anticipate potential POLR needs, even among newly fonning CCAs, the Joint CCAs propose the following example processes for newly registering CCAs to demonstrate the enactment of the necessa1y components outlined in California Public Utilities Code section 366.2.

IV. PROPOSAL
A. Annual Assumptions
Annual assumptions new CCAs use in their pro-fonna financial statements should provide sufficient information to demonstrate forecasted expenses and revenues. 7 This should include, at minimum, how much energy the CCA forecasts it will use to determine energy and Renewables Portfolio Standard (RPS) costs, how much peak demand it will serve to detennine resource adequacy (RA) costs, operations costs including facilities and personnel, and how it will charge its customers to obtain revenues to cover those costs, as follows:
• Annual forecast of financial projections using then-cunent reasonable proxy for energy cost projections and the Energy Resource Recove1y Account Market Price Benchmarks for RA and RPS cost projections;
o RPS cost assumptions should include, at minimum, the minimum RPS requirement in place at the time of the submittal of the pro fonna financial statement.
o RA cost assumptions should include, at minimum, the RA market p1ice benchmark and RA need net of the Cost Allocation Mechanism allocation. • Annual forecast of working capital needs including, at minimum, staffing needs and facility costs; and
• Annual forecast of cashflows, operating reserves, and lines of credit.

B. Milestones
While an Implementation Plan includes essential components, it is the responsibility of a CCA's governing board to determine how objectives are achieved. The suggested milestones do not influence the Commission's ce1tification of a new CCA's Implementation Plan. Per California Public Utilities Code section 366.2, ce1tifications must occur within 90 days, and any additional infmmation requested is solely to assess the need for a cost recove1y mechanism. Fmthe1more, the Commission must specify the earliest possible implementation date for the CCA program.

These milestones do not grant additional authority to deny ce1tification of an Implementation Plan, nor require resubmission or additional info1mation from CCAs with an afready Commission-approved Implementation Plan.
6 D.05-12-041 at 4.
7 These forecasts should be based on the best information publicly available at the time and are subject to change as newer info1mation becomes available.

CalCCA / Joint CCAs T2 Advice Letter
July 17, 2024
Page4
Newly fonning CCAs should incorporate the following best practice milestones to successfully implement a new CCA:
• Develop Implementation Plans
• Create a proposed schedule for key actions, including:
o Adopt and implement staffing plan;
o Secure financing;
o Ve1ify initial load projections;
o Update pro forma financial statements;
o Develop procurement plan for energy, RA, and RPS products; o Adopt rate design; and
o Complete regulat01y registrations needed for California Energy Commission, California Independent System Operator (CAISO), and Commission compliance. • Complete the applicable CAISO requirements checklist or contract with a CAISO-ce1tified Scheduling Coordinator. 8 • Prepare and design customer emollment notices.
• Create a process for notifying customers of their emollment, deliver important updates about their emollment, and collect emollment data.
• Develop and maintain a detailed organization cha1t showing all roles required for responsible and sound operation of the CCA.

V. PROTEST
Anyone wishing to protest this Advice Letter may do so only by electronical mail.

Protests must be received no later than 20 days after the date of this Advice Letter. Protests must be submitted to the Commission's Energy Division at:

E-mail: [email protected]. gov
In addition, protests and all other conespondence regarding this Advice Letter should also be sent by electronic mail, on the same date it is electronically delivered to the Commission, to the attention of:
8 California Community Choice Association
Attn: Evelyn Kahl
General Counsel and Director of Policy
[email protected]
Master Checklist for Ce11ification:
https://www.caiso.com/doclllllents/masterchecklistforce11ification-registrationreguirements.xlsx.

CalCCA / Joint CCAs T2 Advice Letter
July 17, 2024

Page 5 ends

California Community Choice Association
Attn: Elie Little
Director of Regulato1y Affairs
[email protected]
California Community Choice Association
Attn: Lauren Can
Senior Market Policy Analyst
[email protected]
Any person (including individuals, groups, or organizations) may protest or respond to an advice letter (General Order 96-B, Section 7.4). The protest shall contain the following infonnation:
specification of the advice letter protested; grounds for the protest; suppo1ting factual infonnation or legal argument name and e-mail address of the protestant; and a statement that the protest was sent to the utility no later than the day on which the protest was submitted to the reviewing Industly Division (General Order 96-B, Section 3.11).

VI. NOTICE
In accordance with General Order 96-B, Section IV, a copy of this Advice Letter is being sent by electi·onic mail to each pa1ty of record in the official service list for R.21-03-011. For changes to this service list, please contact the Commission's Process Office at (415) 703-2021, or by electronic mail at Process [email protected].

VII. CORRESPONDENCE
All questions concerning this Advice Letter should be directed to Evelyn Kahl at (510) 980-9459, or by electronic mail at: [email protected].

VIII. CONCLUSION
The Joint CCAs respectfully request that the Commission approve the new CCA registi·ation requirements within this Advice Letter.

Respectfully,

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

Service List: R.21-03-011
CCA

ADVANCING LOCAL ENERGY CHOICE

ADVICE LETTER SUMMARY
TO
JOINT CCAS' NEW CCA REGISTRATION REQUIREMENTS TIER 2
ADVICE LETTER PURSUANT TO DECISION D.24-04-009
California Community Choice Association
(510) 980-9459
[email protected]
[email protected]
Evelyn Kahl
July 17, 2024
See Attached 2
Joint CCAs New Community Choice Aggregator Registration Requirements Tier 2 Advice Letter Pursuant to Decision (D.) 24-04-009
D.24-04-009
No
N/A
Upon disposition N/A
N/A
N/A
N/A
N/A
N/A
Clear Form
California Public Utilities Commission
MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Company name/CPUC Utility No.: California Commun.itv Cho.ice Association Utility type: Contact Person: Evelvn Kahl
Ii] ELC □ GAS 0 WATER Phone #: (510) 980-9459
□ PLC □ E-mail: rewa torv<@cal-cca.orll
HEAT E-mail Disposition Notice to: regulatorv<@cal-cca.org EXPLANATION OF UTILITY TYPE (Date Submitted/ Received Sta mp by CPUC) ELC = Electric GAS = Gas
PLC = Pipe WATER= Water July 17, 2024 line HEAT= Heat
Advice Letter (AL) # : See Attached Tier Designation: 2 Subject of AL: Joint CCAs New Community Choice Aggregator Registration Requirements Tier 2 Advice Letter Pursuant to Decision (D.) 24-04-009
Keywords (choose from CPUC listing):

AL Type: D Monthly D Quarterly D Annual IZJ One-Time D Other:

If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution # :

D.24-04-009
Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: No Summarize differences between the AL and the prior withdrawn or rejected AL: / A Confidentia l treatment requested? D Yes [Z] No
If yes, specification of confidential information:

Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/ access to confidential information:

Resolution required? D Yes 1Z] No
Requested effective date: Upon disposition
Estimated system annual revenue effect (%) : N / A
Estimated system average rate effect(%): / A
No. of tariff sheets: N/ A
When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting).

Tariff schedules affected: N/ A
Service affected and changes proposed1= N / A
Pending advice letters that revise the same tariff sheets: N/ A -------------------- 1 Discuss in AL if more space is needed.

General Counsel and Director of Policy
California Community Choice Association
Evelyn Kahl
[email protected]
Lauren Carr
Senior Market Policy Analyst
California Community Choice Association
[email protected]
Clear Form
Protests and correspondence regarding this AL are to be sent via email and are due no later than 20 days after the date of this submittal, unless otherwise authorized by the Commission, and shall be sent to:

California Public Utilities Commission
Energy Division Tariff Unit Email:

EDT [email protected]
CPUC
Energy Division Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
Contact Name: Evelvn Kahl
Title: General Counsel and Director of Policv
Utility/Entity Name: California Community Choice Association Telephone (xxx) xxx-xxxx:

Facsimile (xxx} xxx-xxxx:

Email: re~atory(a}cal-cca.org
Contact Name: Lauren Carr
Title: Senior Market Policy Analyst
Utility/Entity Name: California Communitv Choice Association Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email: lauren(a}cal-cca.org
Clear Form
ENERGY Advice Letter Keywords
Affiliate Direct Access Preliminary Statement
Agreements Disconnect Service Procure1nent
Agriculture ECAC / Energy Cost Adjustment Qualifying Facility Avoided Cost EOR / Enhanced Oil Recovery Rebates
Balancing Account Energy Charge Refunds
Baseline Energy Efficiency Reliability
Bilingual Establish Service Re-MAT / Bio-MAT
Billings Expand Service Area Revenue Allocation
Bioenergy Forms Rule 21
Brokerage Fees Franchise Fee / User Tax Rules
CARE G.O. 131-D Section 851
CPUC Reimbursement Fee GRC / General Rate Case Self Generation Capacity Hazardous Waste Service Area Map
Cogeneration Increase Rates Service Outage
Compliance Interruptible Service Solar
Conditions of Service Interutility Transportation Standby Service Connection LIEE / Low-Income Energy Efficiency Storage
Conservation LIRA / Low-Income Ratepayer Assistance Street Lights Consolidate Tariffs Late Payment Charge Surcharges
Contracts Line Extensions Tariffs
Core Memorandum Account Taxes
Credit Metered Energy Efficiency Te1s.'t Changes
Curtailable Senrice Metering Transformer
Customer Charge Mobile Home Parks Transition Cost
Customer Owned Generation Name Change Transmission Lines Decrease Rates Non-Core Transportation Electrification
Demand Charge Non-firm Service Contracts Transportation Rates Demand Side Fund Nuclear Undergrounding
Demand Side Management Oil Pipelines Voltage Discount
Demand Side Response PBR / Performance Based Ratemaking Wind Power Deposits Portfolio Withdrawal of Service
Depreciation Power Lines

ADVICE LETTER SUMMARY ATTACHMENT

ADVICE LETTER NUMBERS
Advice Letter 16-E Advice Letter 50-E Advice Letter 42-E Apple Valley Choice Energy Ava Community Energy Central Coast Community Energy
Advice Letter 10-E Advice Letter 30-E Advice Letter 31-E Clean Energy Alliance Clean Power Alliance of CleanPowerSF Southern California
Advice Letter 11-E Advice Letter 7-E Advice Letter 30-E Desert Community Energy Energy For Palmclale's Lancaster Energy Independent Choice
Advice Letter 80-E Advice Letter 10-E Advice Letter 36-E Marin Clean Energy Orange County Power Peninsula Clean Energy Authority
Advice Letter 25-E Advice Letter 20-E Advice Letter 11-E Pico Rivera Innovative Pioneer Community Energy Pomona Choice Energy Municipal Ener!!V
Advice Letter 14-E Advice Letter 22-E Advice Letter 22-E Rancho Mirage Energy Redwood Coast Energy San Diego Community Authority Authority Power
Advice Letter 23-E Advice Letter 36-E Advice Letter 7-E San Jacinto Power San Jose Clean Energy Santa Barbara Clean Energy
Advice Letter 33-E Advice Letter 24-E Advice Letter 19-E Silicon Valley Clean Energy Sonoma Clean Power Valley Clean Energy ATTACHMENT A-1
STATE OF CALIFORNIA GAVIN NEWSOM, Governor

PUBLIC UTILITIES COMMISSION
505 VAN NESS AVENUE
SAN FRANCISCO, CA 94102-3298
July 19, 2024 Agenda ID #22771
Ratesetting
TO PARTIES OF RECORD IN RULEMAKING 20-05-003:

This is the proposed decision of Administrative Law Judge Julie A. Fitch.

Until and unless the Commission hears the item and votes to approve it, the proposed decision has no legal effect. This item may be heard, at the earliest, at the Commission’s August 22, 2024 Business Meeting. To confirm when the item will be heard, please see the Business Meeting agenda, which is posted on the Commission’s website 10 days before each Business Meeting.

Parties of record may file comments on the proposed decision as provided in Rule 14.3 of the Commission’s Rules of Practice and Procedure.

The Commission may hold a Ratesetting Deliberative Meeting to consider this item in closed session in advance of the Business Meeting at which the item will be heard. In such event, notice of the Ratesetting Deliberative Meeting will appear in the Daily Calendar, which is posted on the Commission’s website. If a Ratesetting Deliberative Meeting is scheduled, ex parte communications are prohibited pursuant to Rule 8.2(c)(4).
/s/ MICHELLE COOKE
Michelle Cooke
Chief Administrative Law Judge
MLC:jnf
Attachment
FILED
07/19/24
02:58 PM
R2005003
535111325 - 1 -
ALJ/JF2/jnf PROPOSED DECISION Agenda ID #22771
Ratesetting
Decision PROPOSED DECISION OF ALJ FITCH (Mailed 7/19/2024)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking to
Continue Electric Integrated Resource
Planning and Related Procurement
Processes.

Rulemaking 20-05-003

DECISION DETERMINING NEED FOR CENTRALIZED

PROCUREMENT OF LONG LEAD-TIME RESOURCES
R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
- i -

TABLE OF CONTENTS
Title Page

DECISION DETERMINING NEED FOR CENTRALIZED PROCUREMENT OF LONG LEAD-TIME RESOURCES .............................................................................. 1 Summary ....................................................................................................................... 2

1. Background............................................................................................................. 5

1.1. Submission Date .............................................................................................. 8

2. Issues Before the Commission .............................................................................. 9

3. Comments of Parties .............................................................................................. 9

3.1. Resource Eligibility.......................................................................................... 9

3.2. Need Determination...................................................................................... 15

3.3. Relationship to Load-Serving Entity (LSE) Procurement .......................... 23

3.4. Allocation of Costs and Benefits................................................................... 26

3.5. Procurement Process and Timeline.............................................................. 29

4. Discussion............................................................................................................. 34

4.1. Resource Types to be Procured .................................................................... 35

4.2. Need Determination...................................................................................... 45

4.3. Relationship to Load-Serving Entity Procurement..................................... 48

4.4. Allocation of Costs and Benefits................................................................... 53

4.5. Procurement Process and Timeline.............................................................. 55

5. Next Steps ............................................................................................................. 63

6. Summary of Public Comment............................................................................. 63

7. Comments on Proposed Decision....................................................................... 64

8. Assignment of Proceeding .................................................................................. 64 Findings of Fact........................................................................................................... 64 Conclusions of Law .................................................................................................... 66 ORDER......................................................................................................................... 71 R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
- 2 -

DECISION DETERMINING NEED FOR CENTRALIZED

PROCUREMENT OF LONG LEAD-TIME RESOURCES
Summary
This decision makes an initial need determination under the provisions of Assembly Bill 1373 (Stats. 2023, Ch.367), where the California Public Utilities Commission (Commission) may request that the Department of Water Resources (DWR) procure electricity from diverse long lead-time (LLT) resources on behalf of customers of all load-serving entities (LSEs) under the Commission’s integrated resource planning (IRP) purview. This initial need determination totals up to 10.6 gigawatts (GW) of nameplate capacity of the following emerging technologies: up to 7.6 GW of offshore wind (OSW), up to 1 GW of enhanced geothermal systems (EGS), up to 1 GW of multi-day long-duration energy storage (LDES), and up to 1 GW of LDES with a discharge period of at least 12 hours.1 A subsequent informal request may be sent to DWR within six months of the adoption of this decision asking that they initiate procurement activities.

The amounts selected are maximum amounts; once a procurement request is made, DWR will conduct solicitations and evaluate the quality of bids received, including costs and ratepayer risk provisions, and may procure anywhere between zero and the upper limits included in this decision. This flexibility will facilitate cost containment and minimize ratepayer risks.

The specific resources were selected because they are technologies that present opportunities to help California achieve our greenhouse gas (GHG) emissions reduction goals for 2045 and beyond, they represent emerging technologies that need to achieve economies of scale to bring costs down, and 1 All capacity values in this decision are in nameplate capacity, which differs from prior procurement orders, which typically used net qualifying capacity.

R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
- 3 -
they are also not currently being procured by individual LSEs in significant enough amounts to achieve cost reductions. The timing of the need determination herein is also after 2031, thus minimizing potential interference with LSE near-term procurement activities related to LLT resources. Centralized procurement of these resources may also make it easier, in the long term, for LSEs to procure more of these types of resources that may to be vital to achieving our long-term environmental goals.

At the same time, this decision recognizes that electricity rates are rising, creating hardships for ratepayers. Though the DWR centralized procurement mechanism should help bring emerging technologies to scale, the cost of these investments will ultimately impact electricity bills. Accordingly, all possible efforts should be made to contain costs, reduce ratepayer risk, and seek other sources of funding to reduce development costs and share in the long-term costs and benefits.

While we are cognizant that LLT resources targeted by this decision may have higher costs than the prevalent commercialized resources being procured by LSEs today, we also know that these LLT resources are frequently selected as part of our least-cost planning analysis for achieving California’s long-term clean energy goals. Failure to make progress towards procurement of these LLT resources in the short term may ultimately lead to even higher ratepayer costs in the long term, if these resources are needed in the future with a shorter development timeline.

While selection of resources for centralized procurement here is intended to create opportunities for these resources to contributing to meeting our clean energy goals for 2045 and beyond, it is important to note that our determination is only that these resources could contribute to a pathway to meeting those goals, R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
- 4 -
not that these resources represent the only pathway to meeting those goals. We make a considerable need determination here to promote economies of scale that are necessary in order to create an opportunity for these emerging technologies to compete with more mature technologies to become part of our clean energy future, particularly given that economies of scale may be necessary for these resources to successfully compete with more mature technologies.

The total procurement may result in less than the 10.6 GW of total need determination being contracted for, approved by the Commission, and built. We will continue to monitor the procurement process for these resources and adjust other procurement requirements for LSEs accordingly.

LSEs will not be permitted to opt out of their share of centralized procurement authorized herein. The costs and benefits of any DWR centralized procurement approved will be allocated to all LSEs under the Commission’s IRP purview. Additionally, publicly-owned utilities may opt in to allow their customers to share in the benefits of these valuable clean energy technologies.

For Commission LSEs, for EGS and OSW resources, because they are energy resources, the allocation will be on the basis of forecast annual energy load. For LDES resources, because they are capacity resources, allocation will be first to utility service area based on forecast 12-month peak load, and then further allocated to individual LSEs using the same methodology currently used for the Cost Allocation Mechanism.

This decision also requests that, for this LLT procurement, DWR convene a procurement group that includes representatives from LSEs. In addition, the decision sets a tentative schedule of solicitations, asking DWR to conduct two rounds of solicitations for LDES and EGS, beginning in 2026, and three rounds of solicitations for OSW beginning in 2027.

R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
- 5 -
The Commission and staff will work closely with DWR as partners in the design and conduct of the solicitations. Results will be brought back to the Commission for reasonableness review and approval of proposed costs.

Procedurally, Commission review will occur using a mechanism where DWR will submit a formal memo to this proceeding or its successor, and the Administrative Law Judge will then open a separate phase. This separate phase will address issues related to DWR’s recommendations, reasonableness review of any proposed contracts, and the cost recovery for Commission-approved contracts. Finally, the Commission will reevaluate the need determination for additional LLT resources in every IRP cycle when considering a Preferred System Plan portfolio. In the next IRP cycle, the Commission will specifically evaluate LSE progress toward LLT procurement requirements in D.21-06-035, and consider whether an additional need determination for conventional geothermal resources for CPE procurement is necessary.

This proceeding remains open.

1. Background
Assembly Bill (AB) 1373 (Stats. 2023, Ch.367) was passed and signed by the Governor in 2023. AB 1373 authorizes the Commission to request that the Department of Water Resources (DWR) conduct centralized procurement of certain eligible long lead-time (LLT) resources, on behalf of customers of all load-serving entities (LSEs) under the Commission’s integrated resource planning (IRP) purview.

By September 1, 2024, the Commission is required to make an initial need determination for procurement using a centralized procurement mechanism. If a need is found, within six months the Commission may then make a request to DWR to exercise the centralized procurement mechanism. In the event that DWR R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
- 6 -
performs centralized procurement on behalf of customers of LSEs under the Commission’s purview and it is subsequently approved by the Commission, the Commission must then allocate the costs and benefits of any electric resource procurement conducted by DWR.

To make a need determination for the exercise of centralized procurement by DWR, AB 1373, codified as Public Utilities Code2 Section 454.52(a)(4), directs that the Commission “determine if there is a need for the procurement of eligible energy resources based on a review of the integrated resource plans submitted by load-serving entities in compliance with the requirements of this section and Section 454.53 and the progress towards meeting the portfolio of resources identified pursuant to subdivision (a) of Section 454.51.”34 2 Hereafter in this decision, all references to code sections are to the Public Utilities Code, unless otherwise noted.
3 Section 454.53 states, among other things:

It is the policy of the state that eligible renewable energy resources and zero-carbon resources supply 90 percent of all retail sales of electricity to California end-use customers by December 31, 2035, 95 percent of all retail sales of electricity to California end-use customers by December 31, 2040, 100 percent of all retail sales of electricity to California end-use customers by December 31, 2045, and 100 percent of electricity procured to serve all state agencies by December 31, 2035.
4 Section 454.51(a) states that the Commission shall:

Identify a diverse and balanced portfolio of resources needed to ensure a reliable electricity supply that provides optimal integration of renewable energy and resource diversity in a cost-effective manner. The portfolio shall be used by the commission to establish integrated resource planning-based procurement requirements that rely on zero-carbon-emitting resources to the maximum extent reasonable and be designed to achieve the state policy specified in Section 454.53 and any statewide greenhouse gas emissions limit established pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code) or any successor legislation.

R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
- 7 -
On April 26, 2024, the assigned Administrative Law Judge’s (ALJ) ruling (ALJ Ruling) was issued seeking comments on the need and process for centralized procurement of LLTs by DWR in accordance with AB 1373. The ruling discussed resource eligibility, need determination, relationship to LSE procurement, allocation of costs and benefits, and the procurement process and timeline. The ruling also presented the results of a Commission staff and consultant analysis of the cost-effectiveness of offshore wind (OSW), in particular, as well as a qualitative assessment of the other potential eligible resources.

Comments were due by May 24, 2024, and were timely filed by the following parties: American Clean Power – California (ACP-CA); Advanced Energy United (AEU); Alliance for Retail Energy Markets (AReM) and the Regents of the University of California (UC Regents), jointly; Bay Area Municipal Transmission Group (BAMx); BHE Renewables, LLC (BHE); Bioenergy Association of California (BAC); Brightline Defense Project (Brightline); California Independent System Operator (CAISO); California Community Choice Association (CalCCA); California Community Power (CC Power); Public Advocates Office at the California Public Utilities Commission (Cal Advocates); Calpine Corporation (Calpine); California Wind Energy Association (CalWEA); Center for Energy Efficiency and Renewable Technologies (CEERT); California Environmental Justice Alliance (CEJA) and Sierra Club, jointly; California Energy Storage Alliance (CESA); Coalition of California Utility Employees (CUE) and California Unions for Reliable Energy (CURE), jointly; Defenders of Wildlife (DOW); Environmental Defense Fund (EDF); Equinor Wind US LLC (Equinor); Fervo Energy Company (Fervo); Form Energy, Inc. (Form); Golden State Wind LLC (Golden State); Green Power Institute (GPI); Hydrostor, Inc. (Hydrostor); R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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Independent Energy Producers Association (IEP); Invenergy California Offshore, LLC (Invenergy California); Large Scale Solar Association (LSA); Mussey Grade Road Alliance (MGRA); Natural Resources Defense Council (NRDC); Oceantic Network (Oceantic); Offshore Wind California (OWC); Pattern Energy Group LP (Pattern); Protect Our Communities Foundation (PCF); Pacific Gas and Electric Company (PG&E); RWE Offshore Wind Holdings, LLC (RWE); San Diego County Water Authority (SDCWA) and City of San Diego, jointly; San Diego Gas & Electric Company (SDG&E); Southern California Edison Company (SCE); Shell Energy North America (US), L.P. (Shell); Solar Energy Industries Association (SEIA); Swan Lake North Hydro, LLC (Swan Lake); The Utility Reform Network (TURN); Union of Concerned Scientists (UCS); and Vineyard Offshore, LLC (Vineyard).

Reply comments were due on June 5, 2024 and were timely filed by the following parties: ACP-CA; AReM and UC Regents, jointly; BAMx; BHE; Brightline; Cal Advocates; CalCCA; CalWEA; CEJA and Sierra Club, jointly; CEERT; CESA; EDF; Environmental Protection Information Center (EPIC); Equinor; Fervo; Form; GreenGen Storage (GreenGen); GPI; Hydrostor; IEP; Invenergy California; MGRA; NRDC; OWC; PCF; PG&E; RWE; SCE; SDCWA and City of San Diego, jointly; SDG&E; Southern California Gas Company (SoCalGas); Shell; SEIA and LSA, jointly; and Vineyard.

Solar Dynamics, LLC (Solar Dynamics) filed a motion to late-file its reply comments on June 6, 2024; the motion was granted by an ALJ ruling on May 7, 2024.

1.1. Submission Date
This portion of this proceeding was submitted on June 6, 2024, upon the filing of Solar Dynamics’ reply comments.

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2. Issues Before the Commission
The sole issue addressed in this decision is the implementation of AB 1373 (Stats. 2023, Ch. 367), which allows the Commission to request that DWR serve as a CPE for certain LLT resources.5

3. Comments of Parties
This section summarizes the content of parties’ comments on the April 26, 2024 ALJ Ruling by topic area.

3.1. Resource Eligibility
The ALJ Ruling offered four resource types for consideration for centralized procurement by DWR: OSW, Out-of-State (OOS) wind, geothermal, and long duration energy storage (LDES). Parties commenting on the appropriate resource types to be procured were mixed in their opinions. One theme among a plurality of parties was to focus on OSW procurement. Several developers or representatives of particular industries prefer that the Commission require procurement of their specific LLT resource type.

Among OSW lease holders or developers, including Equinor, Golden State, Invenergy California, RWE, and Vineyard, most suggest an initial need determination for OSW. ACP-CA, Invenergy California, CalWEA, Hydrostor, and Vineyard also suggest that the eligibility criteria for resources should be expanded to include resource diversification and other public policy goals.

OWC, Vineyard, and Invenergy California suggest consideration of the additional benefits of OSW, including greenhouse gas (GHG) emissions reduction goals, economic development, job creation, and other non-energy benefits. Brightline suggests that a higher need determination for OSW initially 5 Assigned Commissioner’s Amended Scoping Memo and Ruling Extending Statutory Deadline, April 18, 2024, at 3.

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will help costs decline faster, which is important given the timeline for 25 GW by 2045 included in the California Energy Commission’s (CEC’s) Strategic Plan addressing the AB 525 (Stats. 2021, Ch.231) goals.
6 CEJA and Sierra Club also argue that the non-energy benefits should be included in the criteria, including the social cost of carbon and air quality benefits. EDF agrees that air quality benefits should be included. PCF also argues the Commission should consider additional risk assessment factors such as location, economic risks, and environmental effects beyond carbon emissions.

CEJA and Sierra Club also argue that an important criterion should be consistency with resource needs to meet Senate Bill (SB) 100 (Stats. 2018, Ch. 312) goals. CEJA and Sierra Club support Central Procurement Entity (CPE) procurement of OSW because it can help lead to faster retirement of natural gas plants. In reply comments, Vineyard agrees. Also in replies, Invenergy and RWE point to other state policy goals, including SB 100 and AB 525, as well as major resource potential, resource diversity, cost reductions from economies of scale, and the need for significant development of common infrastructure. Vineyard and EPIC, in replies, also point to the benefits of economies of scale leading to cost reductions, and state that the cost-benefit analysis conducted to date does not adequately account for this.

BAMx seems to prefer that there not be a need determination made at this time for OSW, because the cost of transmission is too high relative to other available resources.

Form recommends that selection criteria should be weighted toward emerging technologies not yet proven on a large scale, and specifically argue for 6 The Final AB 525 Strategic Plan is available at the following link:
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the inclusion of multi-day storage technologies. Fervo argues that enhanced geothermal should be considered separately from conventional geothermal. AEU agrees. Fervo also argues that reliability should be made an explicit value when evaluating resources over multiple days, because geothermal can provide night-time and winter reliability better than other resources. Fervo suggests that the prioritization criteria highlight grid reliability and regional transmission needs.

BHE points out that there should potentially be different treatment for the development of a geothermal field as distinct from a single project, and that initial development of the field is a heavier lift than buildout of a project once the field is already developed.

MGRA argues that pumped storage hydroelectric (PSH) resources should be eligible for consideration, but not the San Vicente project put forward by the City of San Diego and SDCWA, because it is not cost-effective or cost-competitive. PCF also opposes the San Vicente project, and would like to see public ownership explored for other PSH projects. MGRA is concerned that the costs assumed for PSH in RESOLVE modeling do not reflect the costs of pumped storage in California and the site-specific characteristics make a one-size-fits-all approach inappropriate. SDCWA and the City of San Diego argue that the San Vicente project should be procured by DWR, as contemplated in the language of AB 1373, which provides for characteristics of PSH projects that fit the San Vicente situation. Swan Lake advocates for the procurement of its PSH project in Oregon, even though it does not meet the criteria in AB 1373 that a PSH project be “directly appropriated funding by the state before January 1, 2023.”7 7 See Section 454.52(h)(2).

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PCF also argues that OSW and OOS wind are too expensive, and geothermal is already well enough developed and does not need CPE support.

Hydrostor points out that LDES is a broad category, and due to this, each individual technology is valued less in the rating of numerous technologies.

CEERT argues for the inclusion of concentrating solar power (CSP) technologies. Solar Dynamics agrees in reply comments, and suggests that the Commission reassess CSP to reflect the state of CSP technology today and include it in RESOLVE modeling in future IRP cycles.

BAC and GPI argue that bioenergy should be evaluated as a clean firm resource, while GPI acknowledges that emitting resources do not qualify under the language of AB 1373. Still, they argue that these resources should be considered from a broader perspective beyond AB 1373.

Pattern argues that OOS wind should not be considered a proven technology with no opportunity for cost declines, because the use of a CPE may assist in creating cost savings. Pattern also argues that DWR can be considered an anchor tenant to help develop appropriate transmission buildout.

CAISO points to statements within the Commission staff analysis attached to the ALJ Ruling referring to the SunZia project in particular, to conclude that it is unclear that centralized procurement is necessary, given examples of merchant-based transmission moving forward with LSE-level contract commitments. CAISO clarifies that the financing model used for the SunZia project is not applicable for transmission within the CAISO footprint and was specifically designed to enhance opportunities for construction of new transmission in locations currently outside of the CAISO balancing area to facilitate delivery of critically needed resources. In reply comments, AReM and UC argue that there is no consensus for how transmission costs should be treated R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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as part of CPE procurement, and recommend that the Commission set up a process to explore these issues in greater detail. In the meantime, AReM and UC recommend that OOS wind not be eligible for procurement by DWR.

LSE representatives commented with mixed opinions. CalCCA, PG&E, and SCE suggest only considering OSW for centralized procurement, and not any other resource type, and CalCCA would support it only if it does not interrupt individual LSE procurement. Calpine states that the CPE should not be asked to procure resource types that LSEs are already procuring. SDG&E suggests that more criteria should be included prior to making a determination.

CalCCA also suggests the five-year lead-time requirement for resources to qualify for use of the CPE in AB 1373 should not include transmission or interconnection time, but rather only time for the resource itself to come online.

In reply comments, CalCCA states that OOS wind and geothermal have not been demonstrated to take more than five years and LSEs have already demonstrated the ability to procure them individually. Fervo, however, provides evidence for geothermal projects taking five years or more to develop, arguing that the average is closer to seven years.

PG&E prefers no technology carve-outs, especially for pumped storage.

PG&E also comments that the criteria set forth in the ALJ Ruling should be more clearly defined and include more comprehensive condition descriptions.

SCE recommends that the eligibility criteria include the primary question about whether LSEs can procure on their own. SCE suggests that it is premature to conclude that LSEs can’t procure any of the resources. SCE also suggests that the investor-owned utilities (IOUs) should be the CPE instead of DWR. If the Commission moves forward with DWR CPE procurement with technology carve-outs, which SCE does not suggest, then SCE proposes that the technology R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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types be limited to those that are not widely demonstrated. However, SCE also argues that procurement of emerging technologies is also questionable, stating that it is unclear why customers should pay to transform an industry that is not commercially ready, given the many affordability pressures facing customers right now.

CalCCA recommends including resource diversity as an explicit criterion, as do ACP-CA, CEERT, and Invenergy. In reply comments, Fervo agrees.

CalCCA comments that there can be many reasons for otherwise cost-effective resources not being procured in sufficient volumes, including limited availability, transmission and interconnection backlogs, deliverability uncertainty, and large infrastructure needs (such as ports for OSW). CalCCA recommended that the Commission take on these challenges directly, rather than relying on a CPE.

Shell argues that a CPE should be used only when a compelling need to overcome market failures can be identified, such as for OSW currently.

ACP-CA suggests that the CPE structure be assessed for its ability to overcome other challenges/hurdles such as port and transmission infrastructure investment, and expand cost-effectiveness to include economic reliability and GHG benefits over the course of the energy transition.

Finally, IEP prefers that the Commission not list chosen resource types, but rather list only the criteria or attributes of the resources. In reply comments, ACP-CA argues that AB 1373 specifically requires the Commission to “specify resources”8 for DWR central procurement, and thus attributes are not enough. 8 See Section 454.52(a)(4)(B).

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In reply comments, SoCalGas suggests that carbon capture and storage (CCS) and gas-to-hydrogen combustion are emerging technologies providing clean firm electricity that should be considered for procurement by a CPE.

Calpine and MGRA also raised CCS as an option in their opening comments, whereas UCS points out that procuring emitting resources by the CPE is prohibited by the language of AB 1373, which states that DWR can only procure a resource that does not “increase the state’s dependence on any fossil fuel-based resources,” “does not generate electricity using fossil fuels or fuels derived from fossil fuels,” and “does not use combustion to generate electricity, unless that combustion use is ancillary and necessary to facilitate geothermal electricity generation.”9 CalCCA and NRDC also point out in replies that combustion and emitting technologies are not eligible under the AB 1373 provisions. IEP suggests that these technologies be considered in the future outside of AB 1373.

3.2. Need Determination
On the topic of the amount of procurement of particular resources that the Commission should request from the CPE, parties have presented very mixed opinions.

While a good number of parties comment that the preferred system plan (PSP) portfolio is a reasonable place to start for determining need for the various resource types considered, some parties raised specific concerns about that as a need determination source.

PG&E does not support the PSP as a starting point for an OSW need determination, PG&E does not support centralized procurement by DWR for other technology types for a need determination by September 1, 2024, but 9 See Section 454.52(h)(1)(D) and (E).

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argues that the PSP portfolio is a reasonable basis for considering use of the CPE for such resources at a later time in this proceeding, or in a successor proceeding.

PG&E also would prefer that the procurement be done based on attributes that the technology type fulfills, broken down into daily, monthly, or yearly generation profiles.

SCE points out that inclusion of a resource in individual LSE IRPs does not necessarily indicate a need, either for reliability or GHG reduction purposes. SCE also argues that the cost-benefit analysis presented in the ALJ Ruling does not help determine the optimal amount of OSW for the portfolio, but rather just analyzes the various amounts of OSW forced into the portfolio. SCE does support 1 GW of OSW as a prudent start to use DWR as a CPE, arguing this amount is large enough to support a viable project but small enough to minimize risks to customers. PG&E supports DWR soliciting for procurement of up to 3 GW of OSW, but urges the adoption of off-ramps in the event that the projects are too expensive.

SCE comments that there is no need for cost-benefit analysis to determine need, but it can be useful for informing a confidential cost cap and an initial procurement limit for DWR. SCE also states that a cost-benefit analysis alone should not serve as a minimum basis for a non-zero need determination. Instead, SCE suggests that IRP procurement requirements should be driven by matching system needs informed by IRP modeling with the resource attributes that must be satisfied by the procurement, rather than requiring resource-specific technology carve-outs. SCE argues that deviating from competitive, attribute-based procurement often results in uneconomic or suboptimal cost results for consumers. Thus, SCE argues that procurement should be limited to the amount R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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required to bring an emerging technology to the point of being commercially viable.

SDG&E does not support a need determination by specific technology.

Rather, SDG&E argues that all eligible resources should be allocated to participate in a least-cost solicitation, with the best-priced resources selected.

CalCCA is concerned that using the PSP resource amounts has risks, including outdated data, especially for OSW. CC Power similarly argues that the OSW cost estimates are too low in the National Renewable Energy Laboratory Annual Technology Baseline. CalCCA also argues that the PSP does not adequately consider LSE planned capacity, and argues that any need determination made by the Commission here must adequately consider the LSEs’ right to self-procure ahead of authorizing any centralized procurement.

Ultimately, CalCCA argues that the Commission should delay making any need determination until more recent LSE procurement data is available, stating that more OSW through 2028 will be represented than was included in Table 1 of the ALJ Ruling.

LSA generally supports using the PSP as a starting point, except for the OSW amount because it was not selected by RESOLVE but rather forced in on the basis of LSE plans. SEIA supports the Commission making a need determination for OSW of up to 4.5 GW, but proceeding with caution. Invenergy suggests a 4.5 GW minimum, but a total target of 10 GW.

Calpine argues that the Commission should use the least-cost portfolio and not the core portfolio that was selected as the PSP, to determine a need for CPE procurement. Calpine would support an OSW need determination of 1 GW now, and no more than 4.5 GW, stating that OSW is the only resource for which the case for CPE procurement is clear.

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IEP supports 4.5 GW of OSW as a need determination through the PSP, because it aligns with the amount of transmission planning at the CAISO and limits risks to ratepayers by not over-committing to a resource with potentially uncertain procurement costs. IEP would also support an amount of up to 4 GW of OOS wind, because that represents the difference between the PSP portfolio amounts and those planned to be procured by the LSEs in their plans.

BHE makes a similar argument that the amount of procurement ordered through a CPE should be the gap between the PSP resource amounts and those already procured in response to the mid-term reliability (MTR) procurement order (D.21-06-035), in order to prevent a tight market for firm capacity.

The majority of the parties representing OSW interests support a 10 GW need determination for OSW development by 2035. Vineyard, Golden State, and Equinor argue that because 10 GW is the full lease amount so far, it would send the strongest market signal that California wants to develop the potential.

Oceantic also agrees. In reply comments, Invenergy argues that California will only achieve the necessary economies of scale to reduce costs and maximize benefits if the initial need determination is robust, and also states that the 10 GW need not be procured all at once.

Golden State and OWC also support the rationale for procuring LLTs as a “public good”10 on behalf of all ratepayers. Vineyard also suggests that the solicitations for OSW can be broken up into 2 GW tranches evenly spaced out through 2035. Equinor supports the provision that DWR not be required to procure the full amount of the need determination, and that multiple successive 10 See April 26, 2024 ALJ Ruling at 23.

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solicitations could be prudent. CUE/CURE also support a need determination of 10 GW of OSW by 2035.

CalWEA also supports 10 GW of OSW as a need determination, stating that the 4.5 GW in the PSP is not enough. CalWEA argues that updates to RESOLVE would likely show, particularly with reduced transmission costs, that the 10 GW quantity can be delivered at reasonable cost and without significant cost risk.

OWC also supports a 10 GW OSW need determination, arguing that the analysis presented so far does not adequately value diversity benefits. OWC also wants additional consideration of increased federal funding available, and other contributions to the public good, including economic development and job creation. In addition, OWC argues that the Commission should also consider electricity needs to reach the goals in SB 100, the 2022 California Air Resources Board (CARB) Scoping Plan, which calls for 20 GW of OSW by 2045, and the CEC’s AB 525 report, calling for 25 GW of OSW by 2045. Brightline also points to the AB 525 report on OSW, stating that the PSP should not be the exclusive source of need.

EDF also supports a need determination of 7.6 to 10 GW of OSW by 2035 to ensure that leases already awarded reach their full capacity. EDF also comments that the need determination should take a least-regrets approach and build as much as possible, then leverage the tools available to DWR as the CPE to help protect ratepayers so they do not over-buy in the near term. EDF would also support using DWR as the CPE to procure LDES and geothermal later. In reply comments, EDF also points out that the 7.6 GW-10 GW range represents full lease capacity and the cost-effectiveness analysis was too limited temporally to capture the full benefit of OSW over its expected useful life. EDF argues that R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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procurement of OSW is needed now in order to ensure cost-effective procurement through 2045.

In reply comments, EPIC supports a 7.6 GW need determination for OSW as it was shown in the Commission staff’s cost-benefit analysis to represent the level after which ratepayer risks increase. Therefore, EPIC argues this is the minimum need that should be found, and AB 1373 was passed to catalyze the OSW industry, necessitating a “leap of faith.”11
NRDC comments that the staff analysis is a step in the right direction and a reasonable basis for a need determination currently.

CESA is concerned that the PSP understates the need for LDES technologies and the capacity expansion model does not include sufficient LDES durations and technologies as candidate resources with associated cost figures.

Hydrostor comments that the PSP was not developed with the intent to support LLT procurement by a CPE. Hydrostor is particularly concerned about technology neutrality in the LDES category, especially those technologies that are not lithium-ion batteries. In reply comments, Hydrostor points out that many parties arguing in comments that LSEs can procure LDES on their own appear to be referring mainly or exclusively to lithium-ion batteries, and that this is not true for other diverse and emerging LDES technologies.

GreenGen, in reply comments, argues that analysis of the LDES category has been heavily weighted toward lithium-ion batteries, which have a much shorter asset life and do not provide critical grid stability services provided by turbine-based technologies like PSH. GreenGen also points out that PSH 11 EPIC June 5, 2024 Reply Comments at 4.

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technologies do not degrade with each cycle and have useful lives of more than 50 years, which will help stabilize costs over the long term.

AReM argues that lithium-ion batteries should not be eligible to be purchased by the CPE; instead, DWR should focus on other LDES technology types in need of economies of scale and with known longer development times.

Hydrostor agrees.

CESA argues that the LDES procurement to date is insufficient to meet PSP requirements, and therefore a need determination should be made for LDES to be procured by DWR.

CESA points to a joint study conducted by Energy and Environmental Economics (E3), Form Energy, and the CEC12 that reflects the LDES candidate resources with longer durations and accurately reflects the impact of multi-day weather events, modeling the multi-day inter-temporal effects within the resource selection optimization. CESA and Form both argue that intra-day and multi-day storage will likely play an essential role in decarbonizing the electricity sector effectively, noting that the Joint CEC study identifies the need for 5-37 GW of LDES by 2045.

Form further argues that the fact that a specific cost-benefit analysis was not conducted for non-OSW resource types should not prevent the Commission from making a need determination for the other resource types. Form recommends CPE procurement of at least 1 GW of emerging LDES technologies by 2031, including 500 megawatts (MW) of multi-day storage, with at least 2 GW by 2035.
12 The cited study is titled “Assessing the Value of Long-Duration Energy Storage in California.” California Energy Commission Publication Number CEC-500-24-003.

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AEU comments that there was a disparity between the analysis done for OSW and other resource types, and is particularly concerned that the use of 8-hour lithium-ion batteries as a proxy for other resources biases the analysis against geothermal system and LDES. AEU strongly recommends that enhanced or advanced geothermal systems be treated as a separate resource type.

AEU also argues that AB 1373 does not make reference to a quantity of resources, but rather requires the Commission to specify the resources that should be procured to meet that need. Thus, AEU argues that the Commission need not specify the exact quantity of need, but can do this during the six-month period before making the request to DWR to procure. Thereafter, AEU argues that DWR has the flexibility to structure the number and timing of competitive solicitations.

CEJA and Sierra Club comment that the PSP is a reasonable starting point for a need determination, but the high gas retirement scenario should be used to better reflect SB 100 goals. CEJA and Sierra Club also comments that the cost-benefit analysis presented is incomplete, because it fails to meaningfully account for the economic benefits of public entity procurement and the non-energy benefits that result from the construction of diverse resources, including lower air pollution and GHG reductions.

PCF comments that no threshold has been met in the analysis to trigger CPE procurement. PCF especially opposes the CPE being used to procure OSW and OOS wind, but may support LDES. PCF would recommend that the Commission consider authorizing DWR to build and own any additional PSH resources located in California that are cost-effective, reduce GHG emissions, and determined to be needed. PCF further argues that geothermal and PSH R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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resources are already well developed and procurement by DWR would merely serve to reallocate those already-in-use resources to other buyers.

Cal Advocates supports a non-zero need determination for DWR, and comments that the cost-benefit analysis conducted on OSW offers a reasonable basis to conclude that higher levels of OSW are more likely to produce negative net benefits for ratepayers under current assumptions. TURN supports that the need determination be made with each IRP cycle when considering the PSP to be adopted.

3.3. Relationship to Load-Serving Entity (LSE)
Procurement
A majority of parties in comments support the concept that the LLT procurement by DWR as a CPE should be conducted as a public good.13 IOUs, CalCCA, most trade associations, and LLT developers all support this as a general principle. The notable exception is Cal Advocates, which points out that GHG reduction is a fundamental statutory obligation of the IRP process, with or without centralized procurement.

Cal Advocates supports the Commission making a small initial need determination by September 1, 2024, and reevaluating need during the consideration of future PSP portfolios. Cal Advocates further points out that actual cost reductions achieved by DWR procuring an initial tranche of procurement of OSW could move the resource closer to cost-competitiveness in individual LSE solicitations; further volumes of OSW could then be obtained by LSEs without centralized procurement.

Another theme of agreement in the majority of comments with respect to the relationship of DWR centralized procurement and that of LSEs was on the 13 See April 26, 2024 ALJ Ruling at 23.

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issue of allowing a six-month period following the need determination for publicly-owned utilities (POUs) to elect to participate in a DWR solicitation, prior to DWR initiating the solicitation.

Many parties also agreed that the need determination by the Commission should be reconsidered with every IRP cycle, including PG&E, TURN, Invenergy, LSA, Shell, and Vineyard, to name a few. Equinor prefers that the solicitation process by DWR be decoupled and designed outside of the context of PSP adoption and the IRP cycles, and tracked separately. BHE and ACP-CA believe the PSP should be used with flexibility for a more frequent need determination, if needed. GPI opposes this decoupling in reply comments, particularly because assessing need as part of the PSP development process will ensure that transmission development is evaluated at the same time. ACP-CA and Invenergy also request that need determinations not be reduced in subsequent IRP cycles, once made, in order to avoid market confusion.

A more controversial topic in the area of the relationship between potential DWR procurement and LSE procurement is the subject of whether individual LSEs should be allowed to opt out of paying for their share of DWR procurement, in favor of making their separate contracts for needed resources.

CalCCA argues that the Commission must adhere to provisions in Sections 454.51 and 454.52, which include the right of self-procurement by CCAs.

CalCCA argues that these provisions mean that there should be an opt-out opportunity for LSEs, in the six-month period between when the Commission makes a need determination and when the request it made to DWR to procure.

SDG&E also supports the opportunity for LSEs to opt out. MGRA argues that LSEs should be allowed to opt out in order not to penalize early actors.

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SCE and PG&E oppose the idea that LSEs should be allowed to opt out, as do Calpine, NRDC, GPI, and Vineyard. In reply comments, PG&E argues that LSEs can still procure and coordinate with DWR to avoid duplicative procurement. SCE argues that the nonbypassable charge to recover CPE procurement costs should be imposed on all LSE customers. SCE argues that, by definition, a need determination for procurement by a CPE should only be made by the Commission when LSEs are unable to procure a necessary LLT resource.

AReM and UC Regents, in reply comments, state that the size and complexity of LLT projects is beyond the ability of individual LSEs to handle, so procurement would be more cost-effectively and efficiently undertaken by DWR.

CalCCA disputes a similar points made by CUE/CURE, by citing to joint powers authority procurement such as that described by CC Power in its comments.

CC Power points out that even though most parties agree that OSW is the best candidate for CPE procurement, in part because the LSEs have not yet procured it, CC Power has already initiated a solicitation for OSW and consideration of next steps. In addition, CC Power has signed a memorandum of understanding (MOU) with the CADEMO OSW demonstration project, which will develop four floating turbines using existing technology in an area where some electrical infrastructure already exists due to its location near historical oil exploration equipment.

AEU argues that participation in CPE procurement should be optional for POUs, CCAs, and other LSEs, and that DWR should use a subscription model for participation in its contracting.

Invenergy suggests that the Commission plan for a transition from the CPE to LSE procurement in areas where a need is found but the CPE may no longer be needed.

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The CAISO comments chiefly expressed concern that the CPE procurement be reflected in IRP portfolios so that the CAISO can take the resources into account in its annual transmission planning. GPI also commented that the impact of the CPE need determination on the Transmission Planning Process (TPP) is unclear. GPI is concerned that offsetting the need determination from PSP adoption may impact IRP efficiency, pointing out that that the recent PSP may not align with this need determination for LLT resources. GPI is also concerned about the interaction with the reliable and clean power procurement program (RCPPP) expected to be considered in this proceeding later this year.

GPI comments that the LLT need determination for DWR should be assessed in the near term on the same timeframe as other procurement orders prior to the adoption of the RCPPP.

3.4. Allocation of Costs and Benefits
The chief recommendation in the ALJ Ruling around allocation of costs and benefits was that the allocation methodology could mirror the one adopted recently related to the costs for the extension of the Diablo Canyon Power Plant (Diablo Canyon). The method is similar to the Cost Allocation Mechanism (CAM) originally authorized in D.06-07-029, except that costs are spread uniformly across all LSEs subject to the Commission’s Resource Adequacy authority, rather than being differentiated by IOU territory. The ALJ Ruling proposed using a 12-month coincident peak lead method to allocate costs and benefits to each LSE’s customers.

In its comments, SCE suggests that cost and benefit allocation could be one based on energy load share if the purpose of the CPE procurement is GHG reduction. Otherwise, if the procurement is for reliability purposes, then SCE suggests that the proposed 12-month peak allocation is appropriate. PG&E and R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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SDG&E agree with the proposed 12-month coincident peak load. In addition, PG&E specifies that costs are allocated based on forecasting for the applicable year, as opposed to the most recent full year, to remain consistent with the cost allocation for the costs of keeping Diablo Canyon open. CalWEA suggests that the 24-hour slice-of-day framework in resource adequacy should be used as a methodology source for allocation, rather than peak load.

CEJA and Siera Club argue that the CAM for resource adequacy has not been entirely successful, though they do not define their criteria, and therefore they suggest the Commission proceed with caution to ensure environmental, equity, and ratepayer protections are upheld.

Parties were also concerned about the provisions allowing for POUs and/or LSEs to elect to purchase additional resources from DWR on a voluntary basis, beyond the need determination made by the Commission.

PG&E suggests that LSEs and POUs submit their requests for additional procurement by DWR on a capacity basis. SCE suggests that incremental costs should be separately tracked so they are not imposed on other non-participating LSE customers. Further, SCE argues that additional procurement for POUs and other LSEs should be allocated based on the marginal capacity procured. SDG&E agrees that incremental costs should be allocated solely to the LSEs/POUs to avoid any cost shift onto other customers. CalCCA agrees, stating that the Commission must ensure that additional volumes do not increase the costs to those that have central procurement costs allocated to them but did not request additional volumes.

Cal Advocates argues that the Commission should count any voluntary participation from POUs within the CAISO footprint towards the total need determination for DWR centralized procurement. Then, according to Cal R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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Advocates, any participation by non-CAISO POUs should not reduce the total CAISO footprint need determination, as a general matter.

Shell argues that it would be more appropriate, in this case, to allocate the costs and benefits in a similar way to the voluntary auction/market offer (VAMO) process used to allocate the voluntary purchase of renewables from IOUs by other LSEs. Shell also argues that all attributes (energy, capacity, renewable energy credits, and GHG reduction value) should be allocated to LSEs.

NRDC argues that DWR can design its solicitation and contracting process in such a way as to allow LSEs to procure resources beyond the levels in the Commission’s need determination.

Several parties also commented on the likely need for non-energy-related costs, particularly for infrastructure related to OSW development. SCE suggests there should be a distinction made in the solicitation process for costs directly related to the electric system and its development which can be recovered through electric rates and those other costs, such as port and manufacturing facility infrastructure, which are not appropriate to be recovered in electric rates.

For these reasons, SCE supports the development of cost caps. SDG&E suggests that these related infrastructure costs be included in the net present value (NPV) calculations when ranking bids. CalCCA suggests that any costs incurred by developers must be included in the bids, and be part of the bid selection process.

However, CalCCA argues that the Commission must then determine if infrastructure costs are to be separate from the contract for the generation resource. Form suggests that the infrastructure costs should be considered alongside bids from resources that do not require these costs, in order to fairly compare costs.

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CAISO also commented on the transmission costs associated with OSW development. CAISO communicates its commitment to both seeking to prudently manage expenditures that could be the subject of cost recovery processes, as well as providing industry transparency on the pace of transmission development activities and associated cost exposure.

Cal Advocates comments that adding additional costs for port infrastructure to the net benefit analysis reduces the possibility that any OSW is cost-effective.

Cal Advocates also brings up the idea of potentially assigning DWR as the backstop procurement entity in the event that LSEs fail to meet their LLT procurement requirements in D.21-06-035, as amended by D.22-02-004 and D.24-02-047. SDG&E agrees that DWR should be asked to provide backstop procurement for those MTR LLT resources in the event that LSEs fail to procure their required share. AReM also comments that DWR could be an effective backstop procurement entity. UCS comments that the Commission should clarify whether DWR is acting in a “frontstop” or a “backstop” capacity.14 For example, UCS argues that DWR procurement of OSW would be “frontstop,” whereas DWR may want to act as a backstop for OOS wind.

3.5. Procurement Process and Timeline
The ALJ Ruling proposed an application process for the Commission to consider whether to authorize cost recovery through a nonbypassable charge for the resources procured by DWR. Parties were fairly split on whether an application is appropriate or whether a Tier 3 advice letter should be used for Commission approval of any contracts.
14 UCS Opening Comments, May 24, 2024, at 2-3.

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SCE, PG&E, and SCE all support the application process, as does CalCCA.

TURN, CEJA, and Sierra Club agree.

Numerous parties state that they would prefer a Tier 3 advice letter as the vehicle, including Equinor, Invenergy, ACP-CA, and Hydrostor. Cal Advocates would also be supportive of a Tier 3 advice letter process. Form suggests that an application is appropriate for DWR procurement, but a Tier 3 advice letter for IOU procurement.

Several parties comment that DWR may not be as experienced in handling large solicitations as the IOUs, and the IOUs should be considered to assist DWR.

Form makes this point, as does PG&E. SCE suggests that the Commission should consider requesting an IOU to assist DWR in conducting the solicitation, bid evaluation, and/or contract negotiation, with reimbursement for costs by DWR once determined as reasonable by the Commission. GPI suggests that DWR should not be the CPE because of its track record for expensive contracts. GPI suggests instead that the CPE structure in the resource adequacy program, where the IOUs are required to establish independent entities with firewalls to their internal procurement activities, may be the best approach for the LLT resource CPE.

Numerous parties also request that there be a process to develop pro forma contracts or other materials prior to DWR soliciting for any contracts.

PG&E comments that DWR, Commission staff, IOUs and other LSE representatives should develop a contract structure, including a pro-forma contract, to help developers understand expected terms and considerations.

PG&E argues this will help developers form their bids in a solicitation. PG&E also suggests that protocols should be set up for project eligibility, such as CAISO queue position, land rights, federal lease agreements, etc. SDG&E would R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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support a workshop process for the development of a CPE contract template.

CalCCA suggests that prior to initiating procurement activities, DWR should provide its procurement plan, including timelines and contract structures, on the record before the Commission, so that parties can weigh in before the Commission makes a final determination and DWR begins any procurement activities.

In reply comments, ACP-CA disagrees that DWR needs to present a detailed plan before proceeding with procurement, arguing that the AB 1373 requirements are already sufficiently stringent and comprehensive.

In opening comments, CalCCA also stresses the importance of off-ramps baked into the procurement plan. SCE agrees, and stresses the importance of guardrails as part of the DWR solicitation process, to minimize risks to customers. SCE specifically mentions the following elements: use of a competitive solicitation process, establishment of a procurement review group (PRG), Commission approval, flexibility to procure less than the maximum identified need, procurement limits, and a confidential cost cap based on IRP assumptions, industry data, and studies. SCE states that the cost cap can be kept confidential so that bidders do not raise their bids to the level just below the cap.

BAMx agrees in reply comments.

Many parties in comments oppose the use of a cost cap, whether confidential or not, including ACP-CA, Equinor, Golden State, Oceantic, and Vineyard. Oceantic argues that cost caps would interfere with potential developer bidding that can help illustrate the risk, value, and opportunities.

Oceantic also argues that ratepayers will be protected from bids that are too high by the fact that DWR will not be required to purchase up to the total need determination amount, and thus DWR and the Commission may decide to reject R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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bids after evaluating the results of the solicitation. Vineyard agrees with these points in reply comments.

LSA stresses the importance of offramps to minimize risk to consumers.

Another issue discussed in the ALJ Ruling was a structure for a PRG designed to advise DWR on procurement activities and outcomes. The ALJ Ruling suggested that the PRG for DWR should be made up of non-market participants.

SCE strongly advises that the Commission consider allowing LSE representatives to serve on the PRG to DWR, as the LSEs have a vested interest in representing their customers. CalCCA agrees and suggests that the PRG should include at least one representative from each LSE type, including non-market participant CCA representatives.

Cal Advocates suggests that the PRG for DWR be modeled off of IOU PRGs. If the Commission approves a project or multiple projects, Cal Advocates suggests that DWR continue to meet with the PRG to provide progress updates and host any additional meetings for delays, disputes, or any changes to the contract price.

CEJA and Sierra Club suggest that the PRG involve impacted communities, including an option where a community member or organization can participate without reviewing confidential information. Generally, CEJA and Sierra Club suggest that DWR should work with local communities for consideration of their input on contracts. In reply comments, Brightline specifically recommends separate engagement with Tribal Nations. Brightline also suggests that the Commission encourage DWR to take into account the U.S.

Department of Energy’s (DOE) requirements that applicant projects include Community Benefit Plans.

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DOW suggests that the PRG include staff from the California Department of Fish and Wildlife and the Governor’s Office of Planning and Research, as well as non-market participants to provide technical assistance for evaluating potential for environmental and land-use conflicts.

IEP recommends a diverse PRG with industry and community representation.

Another issue parties commented on is the timing of solicitations. ACP-CA, Form, Oceantic, and CESA state that the timeline in the ALJ Ruling is too long for OSW. Golden State and RWE recommend an initial solicitation no sooner than 2026 but no later than 2028. Oceantic suggests that the first solicitation be in 2025. RWE and Oceantic would prefer solicitations on a periodic schedule, around every two years, for additional capacity after the initial solicitation. Equinor also supports periodic solicitations.

Several parties brought up the concept of DWR soliciting for an open-book contract structure, where developers would be paid based on actual costs, with an agreed-upon profit margin. Some parties argue this could be a good option for OSW, since the costs are completely unknown. The approach would be similar to cost-of-service regulation of utilities, where at least initially the contract cost would be transparent to the Commission. BHE, CalWEA, CEERT, IEP, and TURN recommend that the Commission consider this option. SCE agrees in reply comments, and also recommends cost benchmarks and potential off-ramps to protect customers. PG&E also wants the procurement to show a net benefit for customers, along with supporting off-ramps or guardrails.

TURN also generally comments that the Commissions should encourage DWR to consider a variety of alternative contract structures designed to lower costs and maximize ratepayer benefits. GreenGen agrees in reply comments.

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Finally, Cal Advocates recommends that DWR be required to procure bridge capacity in the event of project delays for its assigned procurement.

4. Discussion
This section discusses the determinations that the Commission is making for procurement of several LLT electricity resources in advance of the September 1, 2024 deadline in AB 1373.

AB 1373, codified as Section 454.52(a)(4), directs that the Commission “determine if there is a need for the procurement of eligible energy resources based on a review of the integrated resource plans submitted by load-serving entities in compliance with the requirements of this section and Section 454.53 and the progress towards meeting the portfolio of resources identified pursuant to subdivision (a) of Section 454.51.”
First, as proposed in the ALJ Ruling and supported by the vast majority of parties filing comments, the Commission will plan to evaluate the need for procurement of LLT resources by a CPE on behalf of LSEs under the Commission’s IRP purview with every IRP cycle when the PSP portfolio is being considered. Because numerous factors associated with electricity planning are changing constantly, including cost assumptions, available technologies, and progress toward GHG emissions reduction goals, it is logical that the need for CPE investment in LLT resources should be considered periodically.

Second, the ALJ Ruling also proposed that any non-zero need determination made by the Commission be a maximum procurement amount, but that DWR not be required to procure the full amount if the cost is not reasonable. In other words, DWR would solicit up to the maximum amount requested by the Commission, but DWR could procure any amount less than that, including zero. The ALJ Ruling proposed that DWR not procure these R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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resources at any cost. Almost every party agreed with this proposal in comments. This is also the simplest form of cost containment we can provide for ratepayers in this endeavor, though it is not the only cost containment measure contemplated herein (e.g., Commission review of contracts, pursuant to this decision).

If developers do not offer contract pricing that is attractive from a ratepayer perspective at the time of the offers, their resources are not guaranteed to be bought. Therefore, we will include this policy in our need determinations herein. All amounts will be maximums, with zero as the minimum.

4.1. Resource Types to be Procured
AB 1373, in the sections codified as Section 454.52(h)(1)-(2), defines criteria for resources that are eligible to be centrally procured, as follows:
(1) Only a resource that meets all the following requirements is eligible to be procured by the Department of Water
Resources pursuant to this section:
(A) The resource directly supports attainment of the goals specified in Section 454.53 without increasing the
state’s dependence on any fossil fuel-based resources.
(B) The resource is determined by the Commission to not be under contract at sufficient levels as shown in
load-serving entities’ most recent individual
integrated resources plans submitted to and reviewed
by the Commission pursuant to this section to achieve
the goals specified in Section 454.53.
(C) The resource has a construction and development
lead time of at least five years.
(D) The resource does not generate electricity using fossil fuels or fuels derived from fossil fuels.
(E) The resource does not use combustion to generate
electricity, unless that combustion use is ancillary and R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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necessary to facilitate geothermal electricity
generation.
(2) Resources from a pumped hydroelectric facility may be procured by the Department of Water Resources pursuant
to this section if the pumped hydroelectric facility does not exceed 500 megawatts and has been directly
appropriated funding by the state before January 1, 2023.

The ALJ Ruling recommended that the Commission consider centralized procurement for a LLT resource that provides resource diversity, is needed to meet the goals of Section 454.53, and has already been identified as needed in a PSP portfolio, if it also provides one or both of the following benefits:
• Addresses procurement challenges for existing
technologies, such as when LSEs are currently unable or unwilling to procure the resource individually or at the scale required, because of the size and/or risk profile of the technology; or
• Supports market transformation for emerging
technologies, where the initial procurement creates the potential for future cost reductions through economies of scale or learning about the best ways to conduct resource development.

The ALJ Ruling explicitly identified four potential resource types that meet the criteria given in the statute: OSW, geothermal, LDES, and OOS wind. Each of these resource types has already been identified as part of the most recently-adopted PSP portfolio in D.24-02-047.

We appreciate many parties’ thoughtful comments on the appropriate criteria to be used to select the candidate LLT resources to be procured by a CPE.

We agree with the many parties who asked us to explicitly consider resource diversity as an important and primary criterion to consider in evaluating the need for specific LLT resources. We also note that Section 454.52(a)(1)(J) states R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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that LSEs must “maintain a diverse portfolio of energy resources, which may include eligible energy resources procured by the [DWR].” Section 454.52(a)(2)(B) also states that “the commission may approve procurement of resource types that will reduce the overall emissions of greenhouse gases from the electricity sector and meet the other goals specified in paragraph (1), but due to the nature of the technology or fuel source may not compete favorably in price against other resources over the time period of the integrated resource plan.”15
This represents a second important criterion for the selection of LLT resources to be centrally procured. We are intentionally focused on resources that we believe could be important to the electricity sector as a whole in achieving California’s SB 100 goals by 2045, but which will be inherently more expensive due to their emerging nature and the fact that they are not currently commercially available at competitive prices.

In this way, our action with respect to the LLT resources selected in this decision is intended to bring about market transformation of particular technologies, similar to the manner in which early IOU ratepayer investments authorized via Commission-authorized centralized procurement in solar, wind, and battery storage helped bring down the cost of those technologies in California and worldwide.

Herein, we are explicitly asking LSE ratepayers, through the central procurement mechanism, again to take on the responsibility for making an initial investment in several promising emerging technologies that may prove to be 15 Paragraph (1) refers to the requirement for LSEs to periodically submit individual IRPs, and to address certain policy requirements within them, including, but not limited to, minimizing bill impacts, maintaining just and reasonable rates, and meeting GHG and RPS goals.

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important for achieving SB 100 GHG reduction goals in the electricity sector, as public goods on behalf of all ratepayers under our IRP purview, regardless of their specific LSE.

Because we are taking this approach to market transformation of particular electricity resources, we necessarily must be resource-specific. Once these technologies are available in a widespread manner at lower costs, we will expect them to be able to compete favorably in procurement by LSEs and to be procured in further significant quantities. But right now, the resources we are selecting are inherently more expensive and would be unlikely to be selected in volumes high enough to lead to market transformation by an individual LSE in a least-cost procurement solicitation.

We do expect that some LSEs may begin or have already begun to procure some of these LLT resources in some quantities, and nothing in this decision is intended to prevent or prohibit such procurement. Rather, our approach anticipates that some LSE procurement may occur. In the future, when LSE procurement of these resources is becoming more common, the Commission can limit, reduce, or refine centralized procurement for certain LLT types.

In authorizing procurement up to the amounts detailed in this decision, we seek to create the opportunity for these resources to bid on a competitive basis in order to facilitate this potential market transformation. We do not determine that this volume of these resources is necessary to meet our SB 100 goals.

We also acknowledge the points raised primarily by CalCCA that we are required by Section 454.51(d) to “permit community choice aggregators to submit proposals for satisfying their portion of the renewable integration and diverse resources need identified in subdivision (a).” Subdivision (a) refers to the identification by the Commission of a “diverse and balanced portfolio of R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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resources needed to ensure a reliability electricity supply that provides optimal integration of renewable energy and resource diversity in a cost-effective manner.”
The November 1, 2022 individual IRP filings of LSEs represented the LSE proposals for procuring the diverse resources considered herein. We acknowledge that numerous LSEs, including CCAs, have identified planned resources in their November 1, 2022 individual IRP filings showing an intent to purchase a number of emerging resources, including chiefly OSW, LDES, and geothermal resources. CCAs have shown great initiative in response to the D.21-06-035 requirements and in bringing the CADEMO project under a memorandum of understanding that could lead to a contract. Our intent is not to interfere with any of these efforts or penalize early action by some LSEs for some resources.

At the same time, we also must harmonize the self-provision opportunity for CCAs with the criteria for LLT resources to qualify for CPE procurement that were added by AB 1373, including: “the resource is determined by the commission to not be under contract at sufficient levels as shown in load-serving entities’ most recent individual integrated resource plans submitted to and reviewed by the commission pursuant to this section to achieve the goals specific in Section 454.53 [SB 100 goals].”
While we acknowledge that a number of LSEs have some potential LLT resources under contract in some amounts as shown in the December 1, 2023 and June 1, 2024 confidential procurement data filings, these amounts, while encouraging, are so far not at sufficient levels of LLT resources to achieve our long-term climate goals in SB 100. Thus, the Commission is taking action here to R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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seek CPE procurement that will assist in making it possible for LSEs to procure the necessary LLT resources in the long run.

All LSEs are encouraged to take actions that will contribute to achieving the SB 100 goals, and smaller contracts can offer individual LSEs important portfolio development opportunities, as well as learning opportunities for LSEs in general. In addition, we note below that the quantities of resources procured by DWR will not be the full amount of resources needed in a particular category, which expressly leaves room for LSEs to procure some resources in smaller quantities for various unique reasons.

It is also important to acknowledge here that these resources do not represent the only pathway to achieving our SB 100 goals. We establish this procurement mechanism to enable these resources to compete with more mature technologies to serve as part of our SB 100 energy portfolio.

Thus, our next key criterion is to select resources that are unlikely to be procured by individual LSEs in significant enough amounts due to procurement challenges and market barriers such as risk, size, and cost. If a resource is already under contract in significant amounts and/or is a commercially-available technology, we do not intend to select it as an LLT resource to be procured by DWR as the CPE at this time.

In short, we are viewing the ability to ask DWR to procure resources as a CPE as a unique tool to be used strategically for a chiefly market transformation purpose, for technologies that are likely to be necessary and important to achieving SB 100 GHG reduction goals, but are not yet being procured in sufficient quantities by LSEs.

Turning to the specific resource types, we believe the categories included in the ALJ Ruling are the appropriate ones for current consideration, including:

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OSW, OOS wind, geothermal, and LDES. However, in keeping with comments from several parties representing LDES and geothermal interests, those categories are appropriate to be further differentiated. In a similar fashion to how we have treated wind energy as three separate categories (OSW, OOS wind, and in-state wind), the LDES and geothermal categories are sufficiently diverse to justify sub-categories.

Within the geothermal category, there are numerous geothermal projects that have been developed in California and the West over the past several decades. Conventional geothermal is a fully-commercialized technology, though it may have a higher cost structure than some other resource types due to numerous factors, including its complexity and the need to develop a geothermal field as a fuel source ahead of smaller and more modular generation projects.

Enhanced geothermal systems (EGS) are an emerging technology identified by DOE16 as needing a pathway to commercialization that will require significant capital investment. DOE defines EGS, as distinct from conventional geothermal, in the following manner:

A naturally occurring geothermal system, known as a hydrothermal system, requires three key elements to generate electricity: heat, fluid, and permeability, which is when fluid can move freely through the underground rock.

In many areas, however, the underground rock is hot but there is not enough natural permeability or fluids present. In those cases, an [EGS] can be used to create a human-made reservoir to tap that heat for energy.
16 DOE has an initiative called the “Enhanced Geothermal Shot” that is designed to reduce the cost of EGS by 90% by 2035. See the following link:
https://www.energy.gov/eere/geothermal/enhanced-geothermal-systems#:~:text=The%20Enhanced%20Geothermal%20Shot%E2%84%A2%20is%20a%20depart ment%2Dwide%20effort,geothermal%20heating%20and%20cooling%20solutions.

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In an EGS, fluid is injected deep underground under carefully controlled conditions to create new fractures and cause pre-existing fractures to re-open, creating permeability. Increased permeability allows fluid to circulate throughout the more fractured hot rock, and the fluid becomes hot as it circulates. Operators pump the hot water up to the surface, where it generates electricity for the grid.

EGS could facilitate geothermal development beyond traditional hydrothermal regions, thereby extending geothermal energy production nationwide. EGS advances are being demonstrated worldwide today, in both the public and private sectors.

Unlike conventional geothermal, EGS has little to no air emissions and uses a closed circuit for the fluid underground. EGS can also access deeper and hotter thermal sources, making them easier to site in diverse locations throughout the country, including in California. Finally, like all forms of geothermal energy, EGS has a high capacity factor, but also more flexibility and dispatchability than conventional geothermal.

Due to the important distinctions between conventional and EGS, and the potential for EGS to be important in meeting the SB 100 goals, we will make a need determination for an amount of EGS, potentially to assist with the commercialization of EGS technology in California and worldwide.

While we make a need determination herein for EGS, we also note that there is an enormous amount of technical potential for geothermal energy in the United States, with a large proportion of it available in California.17 A need determination for conventional geothermal is not necessary at this time, however, because the Commission has already ordered LSEs to procure 1 GW of clean, high-capacity-factor capacity in D.21-06-035. This procurement order is 17 See DOE publication “Geovision: Harnessing the Heat Beneath Our Feet,” May 2019 available at the following link: https://www.energy.gov/eere/geothermal/geovision R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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still outstanding, and LSEs are actively soliciting available qualifying resources.

We expect a significant portion of this requirement to be met by conventional geothermal resources. Accordingly, asking a CPE to procure conventional geothermal at this time could interfere with LSE procurement. If procurement of conventional geothermal resources does not materialize in significant enough quantities to meet our long-term clean energy goals, we will consider requiring CPE procurement of conventional geothermal resources in subsequent need determinations associated with AB 1373 requirements.

Within the LDES category, so far most LDES has been procured by LSEs seeking storage with at least an 8-hour dispatch capability. This approach lends itself to procurement of lithium-ion batteries, because they are the cheapest and most modular form of storage, and can be stacked to meet the 8-hour-minimum long-duration requirements.

PSH is another conventional LDES technology that, similar to conventional geothermal, has been commercialized for decades but still may represent a higher-cost option compared to other resource options, particularly compared to lithium-ion batteries currently. While PSH may be more expensive because of the complex siting and infrastructure development required, it is still a well-established technology option.

In this category we agree with Form that as we increase the amount of intermittent resources on our electric grid, we will also increase the need for longer-durations of storage, including greater than 8-hour, as well as multi-day, storage. Our modeling of the LDES category has been necessarily limited by the information we have to rely on for commercially available technologies. Our primary capacity expansion model, RESOLVE, is not currently set up to capture all of the inter-day dynamics related to resources that can be available for long R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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periods of time, such as multi-day storage technologies. Our capacity expansion modeling analysis is based on a limited number of representative days, which can sometimes smooth away fluctuations in generation, load, and other factors that occur during real-world weather conditions. There is also sometimes imperfect information available regarding changing dynamics that affect this type of analysis, such as real-world weather conditions reflecting extreme temperatures, fuel shortages, renewable energy lulls, and reliability events. For these reasons, our capacity expansion modeling analysis using the RESOLVE model may not always identify the need for resources such as multi-day storage that could present value not yet captured in the modeling results.

There are several emerging and developing technologies that can meet a minimum need of 12-hour storage, as well as multi-day storage. More specific duration requirements may be addressed in the procurement request made to DWR within six months. These categories should be differentiated from both PSH and lithium-ion batteries, as uniquely useful to be pursued by a CPE to help develop the technologies and economies of scale necessary to make them widely available and commercially competitive.

Thus, we make a need determination for both 12-hour (or more) storage and multi-day storage, as long as they do not rely on already-commercialized lithium-ion batteries or PSH technologies.

In addition, a majority of parties appear to agree in comments that OSW is an obvious fit for CPE procurement. It represents a significant resource that, if developed, would bring numerous benefits to California, both energy and non-energy benefits (such as economic and port development), assuming it can be developed at reasonable cost. Though many LSE plans indicate interest in procuring OSW, it also has not been contracted in any significant way by LSEs to R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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date. Thus, asking a CPE to procure OSW would not interfere with LSE procurement. For all of these reasons, we make a need determination for procurement of an amount of OSW.

We note that we are not persuaded to select OOS wind for procurement by a CPE at this stage. OOS wind has already been successfully procured in reasonably significant amounts by LSEs. In addition, recent developments with subscription models for transmission access to OOS wind may help improve the ability of LSEs to procure additional amounts of OOS wind. Thus, we will not include a need determination for any OOS wind in this decision. We will watch the market for OOS wind and potentially consider the use of a CPE for OOS wind in the future.

In summary, as stated above in this section, the Commission finds a need for the centralized procurement of four different types of resources: 1) EGS; 2) 12- hour or more emerging LDES technologies, that are not lithium-ion or PSH; 3) emerging multi-day LDES technologies, that are not lithium-ion or PSH; and 4) OSW.

4.2. Need Determination
For clarity, we begin with an explicit definition of “need determination” in the context of AB 1373 determinations by this Commission. We will define “need determination” as follows: the maximum value determined by the Commission to be procured by a CPE for a given resource type and/or resource attribute(s), on behalf of all LSEs under the Commission’s IRP purview.

The most recent PSP portfolio adopted in D.24-02-047 included the following resource need amounts (in nameplate) by 2035 that are relevant to the eligible resources already discussed above:

1. Geothermal: 2,000 MW;
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2. Generic LDES: 500 MW;

3. 8-hour batteries: 2,800 MW;

4. PSH: 500 MW; and

5. OSW: 4,500 MW.

As most parties are aware and has been covered numerous times with respect to the assumptions used for RESOLVE capacity expansion modeling, in the LDES category certain technologies are used as proxies for the category as a whole, since the category contains a diverse set of technologies. Thus, for the purpose of making a need determination for DWR to solicit for, we will look at the total LDES in the portfolio, which is 3,800 MW by 2035.

In considering how much of each type of resource to determine is needed, for the geothermal and LDES categories, we determine that it is reasonable to make a need determination for roughly half of the quantities shown in the PSP portfolio to be procured using the CPE mechanism. Procuring up to this maximum amount will make a significant investment in the resource types identified, while still leaving significant volumes for LSEs to procure on their own, assuming the planned-for market transformation occurs and costs are reduced during or after the DWR procurement phase.

This means, we are making a need determination for up to 1,000 MW of EGS and up to 2,000 MW of emerging (non-lithium-ion and non-PSH) LDES (up to 1 GW of 12-hour+ duration and up to 1 GW of multi-day). As mentioned above, asking a CPE to procure the first half of these categories still leaves room for LSEs to procure more of these types of resources, should they so choose and/or if costs come down. It is also likely that future PSP portfolios may show the need for additional amounts.

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We have considered the appropriate quantities of OSW in a somewhat different manner. First, as explained in D.24-02-047, the quantities of OSW in the PSP portfolio were selected to be consistent with the amount of OSW included in the portfolio sent to the CAISO for the prior year’s (2023-2024) TPP base case.

The amount of OSW represented in the individual LSE plans was less than 4,500 MW. At the other end of the spectrum, the full buildout of the current leaseholders from the U.S. Bureau of Ocean Energy Management (BOEM) auction for California call areas estimated by OSW developers is approximately 10,000 MW. And as cited by several parties in comments, the AB 525 Strategic Report includes 25,000 MW of OSW by 2045 as a goal. As with LDES and EGS, we want to leave room for LSEs to conduct individual procurement separate from DWR’s initial tranche of investment. The CPE investment is likely to be at a scale that is too difficult for an individual LSE or group of LSEs to integrated into their plans because of size, timing, or development risk factors. We also do not want to create unnecessary market power by requesting that a CPE purchase the entirety of the capacity represented by the current leaseholders.

Looking at the cost-benefit analysis conducted by Commission staff, which considers the likelihood that benefits will exceed costs at particular levels of capacity procurement, the 7.6 GW scenario analyzed appears to be the level beyond which, based on current assumptions, it becomes more likely that the costs of procuring the OSW will exceed benefits in cost savings to electricity ratepayers. Beyond that level, net benefits currently appear to be lower, largely due to more expensive transmission upgrade costs and declining marginal benefits.

Our desire in the OSW category is to signal our strong interest in developing the resource and investing up front in order to achieve the economies R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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of scale that will be necessary eventually to realize the full benefits of the resource potential by around 2045. In addition, 7.6 GW represents the full physical cap for Morro Bay and Humboldt OSW resource buildout from a transmission perspective.

Finally, the 7.6 GW level of procurement achieves a good balance between the 4.5 GW in the most recent PSP portfolio and the maximum lease amounts available currently. For all the above reasons, we will adopt 7.6 GW as the maximum OSW need determination for DWR to seek to procure.

As already stated above, we emphasize that we will regularly evaluate the need for additional centralized procurement of these resources with each IRP cycle.

In summary, Table 1 below shows our total need determination quantities and categories.

Table 1. Need Determination Quantities
Resource Type Quantity (Nameplate)
EGS 1 GW
LDES: 12-hour + duration 1 GW
LDES: Multi-day 1 GW
OSW 7.6 GW

4.3. Relationship to Load-Serving Entity Procurement
The ALJ Ruling proposed that an initial tranche of OSW be procured by DWR as a public good, with the purpose of investment in GHG reductions for California as a whole, specifically to attain the goal set forth in Section 454.53 (from SB 100). The same logic included in the ALJ Ruling for OSW is also R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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applicable to procurement of EGS and the two types of non-lithium-ion and non-PSH LDES identified in Section 4.1 above.

We note that we have targeted resources for procurement in Section 4.1 above that are intentionally different from resources already being procured by LSEs directly at sufficient volumes to result in market transformation, with the explicit intent not to interfere with LSE procurement and, in fact, to offer advantages to LSEs who may want to procure these types of resources in the future at more competitive prices.

The ALJ Ruling also proposed that any CPE procurement of resources would not count toward current procurement requirements of D.21-06-035, D.23-02-040, or D.24-02-047. Any CPE procurement would be kept separate from any LSE-specific requirements.

Here we note that all three of the above-referenced decisions relating to MTR procurement contain requirements for our IRP LSEs collectively to procure at least 2,000 MW of LLT resources with certain characteristics by no later than June 1, 2031. We agree that the resource procurement we are seeking from DWR through this decision should be treated separately from the MTR LLT procurement by LSEs. The MTR procurement is likely to involve established commercially-available technologies, whereas we are intentionally targeting emerging technologies with procurement by a CPE. In addition, the timing will be different, as described further below in Section 4.5. We will ask DWR to solicit for LDES and EGS resources with online dates after June 1, 2031; therefore, CPE procurement should not interfere with any LSE procurement to meet the MTR requirements.

The purposes of the LSE LLT procurement for MTR and CPE LLT procurement are distinct and complementary and therefore CPE procurement of R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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LLTs will not count toward any current requirements of D.21-06-035, D.23-02-040, or D.24-02-047.

The ALJ Ruling also proposed that any CPE procurement be kept separate from any LSE-specific requirements that may be included in the RCPPP, which has not yet been adopted, but is intended to replace the order-by-order procurement requirements used in IRP to date. The RCPPP is intended to cover both reliability- and GHG-driven procurement needs.18
We agree that it is logical to keep any CPE procurement as a result of this order separate and apart from any individual LSE requirements driven by the RCPPP, once adopted. Since LSEs will not have control over the timing or the amount of CPE procurement, it will be simpler for all actors if the CPE procurement is treated as a separate category, and not co-mingled with the LSEs’ own procurement. In addition, we expect the RCPPP and its ultimate design not to have any bearing on CPE procurement requested in this decision.

The ALJ Ruling also proposed that LSEs not be allowed to opt out of CPE procurement once the Commission makes its need determination, as we are doing in this decision. Thus, all LSE customers would pay for the centralized procurement. Here we agree strongly with the ALJ Ruling’s proposal for no individual LSEs being allowed to opt out. As noted several times already, we are selecting resources that are not being procured by LSEs currently in significant enough amounts to create market transformation. Thus, we are targeting resources, by definition, that are not competing in a significant way with LSE procurement currently. LSEs had the opportunity, in their November 1, 18 For more information about consideration to date, see the September 8, 2022 ALJ ruling available at the following link: https://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat-ALL&DocID=496688637.

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2022 individual IRP filings, and the subsequent semi-annual procurement data filings, to show their progress toward procurement of LLT resources and did not show that they are currently being procured by individual LSEs in significant enough amounts to achieve cost reductions.

Therefore, we are electing to ask DWR to attempt to procure resources as essentially a “downpayment” toward further future procurement by LSEs directly. Therefore, all LSEs will share equally in the risks (including timing, costs, and general development risks) and rewards (increment new clean energy resources that provide reliability, GHG benefits, and energy benefits) associated with collective action. Basic fairness dictates that the customers of all LSEs under our IRP purview should pay equally for this procurement. Once the Commission has sought DWR procurement after its review of procurement plans of LSEs under the Commission’s IRP purview, as we are doing in this decision, AB 1373 does not provide for LSEs to opt out of costs for any centralized procurement once it is authorized to be undertaken.

Further, the Water Code additions19 in AB 1373 require that the costs of DWR procurement of diverse LLT resources be paid for using a nonbypassable charge. This is consistent with the principle that all LSE customers should pay for the centralized procurement. Allowing LSEs to opt out after DWR has been asked by the Commission to undertake procurement on behalf of the LSEs would create an unworkable situation and thwart the statutory framework.

The ALJ Ruling also notes that POUs are permitted, by provisions in Water Code Sections 80820, 80822, and 80826, to voluntarily opt in to CPE procurement.

This is a meaningful opportunity for POUs to help drive market transformation 19 See, for example, Water Code Section 80821.

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of emerging technologies and support California’s clean energy and climate goals. The ALJ Ruling proposed that any provisions for these resources be handled directly between DWR and the POUs, without involvement of the Commission.

Here, we note that AB 1373 provides for a six-month period between the Commission making a need determination for centralized procurement and the Commission making a request to DWR to initiate procurement activities based on that need determination. It would be logical for any POUs wishing to join in the centralized procurement to make the election during this six-month period, so that DWR is able to plan for the total procurement requested and solicit for all of it at the same time, without advantaging or disadvantaging any group of LSEs or POUs in any individual solicitation.

We also note here our policy concern that POUs are not also required to invest in the resources that will be centrally procured under AB 1373. This investment should not be voluntary for the approximately 25 percent of customers in California who are served by POUs, because the investments are for the benefit of all Californians.

For at least the last 25 years, the lion’s share of investments in resources that will help achieve the SB 100 goals, including investment in research, development and demonstration; renewables; energy storage; energy efficiency and demand response; and electric vehicle infrastructure; just to name a few, have been made by electricity customers who are under Commission jurisdiction and customers of IOUs and CCAs. It is inherently discriminatory and unfair not to require all electricity ratepayers in California to share equally in the investment for the good of all. In addition, it creates unnecessary and undesirable pressure on electricity rates for IOU distribution customers who are R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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already struggling with electricity affordability. We are hopeful that POUs will welcome the opportunity to contribute to the efforts to develop new clean energy resources with accompanying benefits.

4.4. Allocation of Costs and Benefits
The ALJ Ruling proposed that the costs and benefits of any centralized procurement be based on the IOU statewide allocation approach used by the Commission for the costs of retaining Diablo Canyon.20 Namely, the costs of centrally procured resources would be allocated first to each IOU service area based on the IOU transmission access charge (TAC) area share of a 12-month coincident peak load, minus any non-benefitting POU load in that TAC area, and based on the share that occurred in the most recent full year that ended before the costs are allocated. Then, the ALJ Ruling proposed that the allocation to individual LSE customers within each IOU’s territory could mirror the approach used in the CAM.21 This would result in the application of nonbypassable charges to all LSE customers.

The ALJ Ruling proposed that the benefits of CPE procurement be allocated in the same manner as costs, basically mirroring CAM allocation of resource adequacy and GHG emissions reduction benefits. The benefits could also be used to inform the Power Source Disclosure Program that is overseen by the CEC.

For cost and benefit allocation methodology, the proposal in the ALJ Ruling is logical for the LDES resources, which are chiefly capacity resources.

Thus, allocating to IOU service area, and then further differentiating by LSE, 20 See D.23-12-036, Sections 6-7.
21 CAM was originally adopted in D.06-07-029.

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annually on the basis of the 12-month forecast peak demand is consistent with the benefits delivered by the LDES resources, and is intended to be consistent with past CAM practice for consideration of CAM credit allocation. The difference in this instance is that the forecast will be a statewide forecast, and not by TAC area which is typically used for CAM credit allocations. Commission staff should use the most recent vintage of demand forecast for each year’s allocation, including any future year forecasts of future allocations. We will adopt this approach for any of the LDES resources that DWR may procure.

Consistent with past CAM practice, we expect the capacity costs to be charged to all customers, after netting any associated energy rents that might be associated with particular contract types.

The Commission also will not dictate the type of contract that DWR might enter into for LDES resources. It may be Resource Adequacy only or combined with energy deliveries. Historically, some CAM contracts have included energy dispatch rights and thereby provided energy revenues associated with the dispatch of the resources through the energy markets; the energy revenues were netted from the capacity cost prior to costs being charged to all customers.

We note that one reason the Commission required IOU procurement of LLT resources starting in 2004 was that large IOU-controlled resources were subject to cost-based bidding rules by the IOU procurement plans. The IOU CAM procurement contributed to a hybrid wholesale market where IOU-controlled resources bid into the market at cost to help mitigate the potential exercise of market power by wholesale generators. In today’s market context, we observe that LSEs have entered into large volumes of capacity-only contracts to meet IRP requirements, and we have entered a new era where LSEs could be subject to high wholesale energy bidding behavior. We encourage DWR to R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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consider this history while considering the type of contracts to execute with resources that provide both capacity and energy benefits.

For EGS and OSW, we agree with the proposal by SCE in its comments that the resources that are energy-heavy would be more logically allocated on the basis of energy load share served among LSEs, rather than coincident peak demand. An advantage of this approach is that it can be done at the individual LSE level, without the need to allocate by IOU TAC area first. Thus, we will require that the costs and benefits of EGS and OSW be allocated annually based on a pro rata share derived from forecast loads. Commission staff should use the most recently available vintage of load forecast for each year’s allocation, including any future year forecasts of future allocations.

Further implementation details to operationalize this policy may need to be addressed by the Commission in this proceeding prior to or during consideration of actual projects to be contracted by DWR.

4.5. Procurement Process and Timeline
The ALJ Ruling proposed a few key aspects of the procurement process to be undertaken by DWR:

1. All procurement should be conducted via a competitive solicitation process;

2. All proposed contracts should be submitted by DWR to the Commission for approval via an application, leading to a Commission decision on the contracts and their cost
recovery; and

3. All contract volumes and pricing data can be submitted by DWR as confidential for a period of three years after
approval (or rejection) by the Commission in a decision.

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All parties support competitive solicitations for the purpose of procuring eligible LLT resources. This is also contemplated in the direction to DWR in the Water Code included in AB 1373. Thus, we will require competitive solicitations.

A number of parties recommended an advice letter process for Commission approval of any DWR contracts, rather than an application process.

We are concerned that the advice letter process is too informal and will not allow for a full enough vetting of any proposed contracts. At the same time, we are undertaking this process with DWR as a partner, conducting procurement on behalf of the Commission and all LSEs under our IRP purview. It therefore seems inappropriate to ask DWR to submit an application as a supplicant before the Commission, since DWR is not a Commission-regulated entity.

Instead of either of these processes, we will model our approach on the way that the Wildfire Non-bypassable Charge emanating from AB 1054 (Stats. 2019, Ch. 79) is handled by the Commission and DWR. This process was established in D.19-10-056, and requires DWR to submit a memorandum to the Commission detailing the costs to be recovered from the participating IOUs via a nonbypassable charge; the ALJ then issues a ruling asking parties to comment on DWR’s memorandum, and takes the additional steps necessary to render a Commission decision authorizing the cost recovery. The circumstances here are similar, where DWR is acting on behalf of ratepayers of all LSEs under our IRP purview. Therefore, instead of an application, we will ask DWR to submit a detailed memorandum summarizing all aspects of the process used in its solicitation, as well as the results and costs. The ALJ in this or a successor IRP proceeding will then issue a ruling establishing a separate phase of the proceeding and seeking party comment on the proposed contracts. Ultimately, this process will lead to a Commission decision approving or rejecting the R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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contracts, along with applying the adopted cost recovery mechanism. Consistent with direction in AB 1373, we expect this will be a nonbypassable charge on distribution customers.

On the confidentiality of DWR contracts and prices, we will generally follow existing and already-established rules for how confidentiality of procurement contracts is handled, as established in D.06-06-066 and its successor decisions. However, as proposed by numerous parties in comments, we will also recommend to DWR that they consider soliciting open-book bids for provision of some resources. Using open-book bidding, proposed contracts contain placeholder values, and the actual costs of the contract may be permitted to go up or down, depending on the actual costs incurred. We do not require this approach, partly because this option may necessitate a different approach to confidentiality, since the contracts would allow DWR to pay developers based on actual costs, which would be revealed to DWR and the Commission, but still remain otherwise confidential. Thus, those types of contracts may need to remain confidential for much longer than other types. For these types of open-book contracts, we will refrain from making any detailed rules about confidentiality in this decision, and instead will address this in the context of individual contracts presented to us for consideration by DWR in the future.

Water Code Section 80820 also requires that the Commission and DWR establish a “procurement group” to advise DWR on any procurement undertaken. The ALJ Ruling suggested that this group be convened by and advisory to DWR and consist of non-market-participants, as well as agency staff.

The ALJ Ruling also proposed that DWR be encouraged to retain an expert consultant to advise on the procurement as an independent evaluator and/or support for DWR staff procurement determinations.

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No party objected to the idea that DWR retain an expert consultant; this approach has worked well for IOU procurement, and therefore we will recommend this approach to DWR. It may provide assistance both in the preparation of the solicitation, as well as in evaluating bids.

As far as the composition of the procurement group, numerous parties suggested it be modeled on the PRG structure used by the IOUs. Several LSEs also argued in comments that LSE representatives should be allowed to serve on the procurement group, since they (and their customers) have a vested interest in the outcome of DWR’s solicitations. LSE representatives who are directly involved in conducting solicitations for LSEs should not also serve on the procurement group as advisory to DWR. However, we are persuaded that LSEs should have representation on the procurement group, both because they may have expertise to bring to the table and because their ratepayers will ultimately be paying the costs of DWR’s contracts. Thus, we will ask that DWR include at least one representative of a community choice aggregator (CCA) organization, at least one representative of an electric service provider (ESP) organization, and at least one representative of an IOU who is not otherwise involved in assisting DWR with solicitation activities. Though we do not specify the inclusion of POUs, we observe that if a POU has requested procurement by DWR, it may also be logical to include a POU representative on the procurement group.

In addition, a number of parties recommend that DWR be encouraged to conduct outreach to and allow representation on the procurement group from community groups and Tribal Nations with vested interests in the procurement.

We agree, and encourage DWR to use the input from these groups as much as possible.

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When DWR submits its memo to the Commission detailing its solicitation activities and results, we will ask that DWR identify the individuals involved in the solicitation process, either in a direct advisory capacity and/or as procurement group participants during the solicitation, and we will require that DWR not allow individuals to participate in the solicitation process if they have participated in the procurement group (and vice versa) during the course of a single solicitation.

The ALJ Ruling also included an outline of a proposed schedule for DWR to prepare and issue a solicitation. Generally, preparatory activities were suggested for 2025-2027, pre-bid activities in 2026-2027, with solicitations open for bid between 2026 and 2028, bid evaluation in 2027-2028, and contracts submitted to the Commission in 2027-2028.

A number of parties commented that this schedule outline was somewhat too slow to attract enough interest from developers. At the same time, we are cognizant of the fact that DWR will need time to put together its team to handle the solicitations and all of the tasks leading up to them. Thus, the schedule we put forward below provides a general framework, but we expect adjustments will need to be made as this effort progresses. We also expect that DWR itself will want to present at least some aspects of its plans to stakeholders to receive feedback prior to launching any solicitations. We will defer to DWR’s judgment on the best way to do this, but note that because of the groundbreaking nature of this procurement, it may be preferable to err on the side of transparency and inclusiveness in terms of allowing ample stakeholder feedback on DWR’s approach.

In terms of the schedule for solicitations, we also note that the volume of resources contained in the need determination in this decision is large. Therefore, R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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it will likely be prudent for DWR not to conduct a single solicitation for the full amount. Instead, we recommend below a schedule of solicitations designed both to take advantage of learning by starting small, as well as the fact that some projects may not yet be ready to participate in a first solicitation, but could be ready by a subsequent solicitation round.

We also expect that DWR will need all of 2025 for preparatory activities for solicitations, such that 2026 is the first realistic year that solicitations could begin.

With that in mind, we adopt the following solicitation schedule as a framework to organize the process. Timing reality may deviate from these plans somewhat, but our staff will work closely with DWR to execute this plan.

Table 2.

Recommended Approach and Indicative Timing for LLT Solicitations Activity Timing Target
DWR preparatory activities, including formation of
procurement group
Late 2024 and 2025
DWR development of solicitation plans and materials, in consultation with Commission staff and procurement
group
2025
First LDES Solicitation –
Up to 1 GW of multi-day storage and up to 1 GW of 12+-hour duration storage, for deliveries beginning June 1, 2031 through June 1, 2035 Pre-bid activities Early 2026
Solicitation open for proposals Late 2026
Proposed contracts submitted to Commission for
approval
Mid 2027
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Activity Timing Target
First Enhanced Geothermal Solicitation –
Up to 1 GW for deliveries beginning June 1, 2031 through June 1, 2035 Pre-bid activities Late 2026
Solicitation open for proposals Early 2027
Proposed contracts submitted to Commission for
approval
Late 2027
First OSW Solicitation –
Up to 7.6 GW, for deliveries by June 1, 2035
Pre-bid activities Early 2027
Solicitation open for proposals Late 2027
Proposed contracts submitted to Commission for
approval
Mid 2028
Second LDES Solicitation –
Residual amount not procured in first LDES solicitation, of up to 1 GW of multi-day storage and up to 1 GW of 12+-hour duration storage, for deliveries beginning June 1, 2033 through June 1, 2037
Pre-bid activities Early 2028
Solicitation open for proposals Late 2028
Proposed contracts submitted to Commission for
approval
Mid 2029
Second Enhanced Geothermal Solicitation –
Residual amount not procured in first EGS solicitation, of up to 1 GW, for deliveries beginning June 1, 2033 through June 1, 2037
Pre-bid activities Late 2028
Solicitation open for proposals Early 2029
Proposed contracts submitted to Commission for
approval
Late 2029
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Activity Timing Target
Second OSW Solicitation –
Residual amount not procured in first OSW solicitation, of Up to 7.6 GW, for deliveries by June 1, 2036
Pre-bid activities Early 2029
Solicitation open for proposals Late 2029
Proposed contracts submitted to Commission for
approval
Mid 2030
Third OSW Solicitation –
Residual amount not procured in first and second OSW solicitations, of Up to 7.6 GW, for deliveries by June 1, 2037
Pre-bid activities Late 2029
Solicitation open for proposals Early 2030
Proposed contracts submitted to Commission for
approval
Late 2030
We note that the quantities in each solicitation listed above may be adjusted downward in the second and third rounds, depending on the amount of contracting actually approved at the conclusion of the prior solicitation rounds.

We also recognize that the above table represents a plan that will likely change. Thus, we request that DWR send periodic or interim updates on progress and changes to solicitation schedules to the Executive Director of the Commission, with a copy to the relevant IRP service list and Energy Division (at [email protected]). DWR should update the Commission at least annually, or more frequently after major milestones or with schedule changes, in advance of submitting a formal Memorandum to the Commission detailing procurement results.

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5. Next Steps
We note that AB 1373 gives the Commission six months after the initial September 1, 2024 need determination deadline to make a procurement request to DWR to initiate the necessary procurement. We will define a “procurement request” as follows: after a need determination is made by the Commission, the Commission will send a procurement request to the CPE triggering the initiation of the procurement process.

We expect that procurement request to be informal, likely in the form of a letter from the President of the Commission asking that DWR formally initiate procurement activities. The Commission may, at this point, add additional clarification or details regarding recommendations to the solicitation process at that time, consistent with the framework in this decision. And as already stated above, we intend to work closely with DWR throughout the solicitation process, at the staff and leadership levels.

Finally, after each solicitation round is completed, the Commission may choose to revise or send a subsequent procurement request, reflecting the results of contracting from the prior round.

6. Summary of Public Comment
Rule 1.18 allows any member of the public to submit written comment in any Commission proceeding using the “Public Comment” tab of the online Docket Card for that proceeding on the Commission’s website. Rule 1.18(b) requires that relevant written comment submitted in a proceeding be summarized in the final decision issued in that proceeding.

One public comment was submitted by EPIC, an organization which also submitted formal reply comments in response to the ALJ Ruling. EPIC’s public R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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comment echoes its formal reply comments. No other public comments were submitted.

7. Comments on Proposed Decision
The proposed decision of ALJ Julie A. Fitch in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission’s Rules of Practice and Procedure. Comments were filed on __________, and reply comments were filed on _____________ by ________________.

8. Assignment of Proceeding
Alice Reynolds is the assigned Commissioner and Julie A. Fitch is the assigned Administrative Law Judge in this proceeding.

Findings of Fact

1. An optimal electricity portfolio, as adopted by the Commission as part of each PSP, is a product of a series of changing factors, including cost assumptions, available technologies, and GHG emissions reduction goals.

2. The resource types considered for a need determination for centralized procurement are geothermal, LDES, OOS wind, and OSW.

3. Geothermal electricity, OOS wind, lithium-ion battery LDES, and PSH are a commercialized technologies.

4. EGS is an emerging technology distinct from conventional geothermal, and is the subject of an initiative at DOE called “Enhanced Geothermal Shot” designed to reduce the costs of EGS.

5. 12+-hour LDES and multi-day LDES are emerging technologies that are not yet sufficiently available with known costs to be modeled in previous PSP portfolios adopted by the Commission. Therefore, proxies have been used.

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6. OSW is an emerging technology with very few deployments worldwide in deep-water locations such as the California coast.

7. As of this decision, numerous LSEs have OOS wind projects under contract. Some also have conventional geothermal, EGS, and 8+hour LDES projects under contract.

8. As of this decision, almost no LSEs have EGS, 12+-hour LDES, multi-day LDES, or OSW projects under contract. Those LSEs that do have these types of projects do not have any significant volumes under contract relative to the size of the resource potential or in enough quantities to spur market transformation.

9. The PSP portfolio adopted in D.24-02-047 included the need for nameplate capacities of 2,000 MW of geothermal; 3,800 MW of LDES; and 4,500 MW of OSW, by 2035.

10. OSW developers state that current BOEM leaseholders for OSW projects have a potential capacity of approximately 10,000 MW.

11. Asking a CPE to procure all OSW BOEM leaseholder capacity has the potential to result in the exercise of market power.

12. The November 1, 2022 individual LSE IRP filings represented the CCAs’ opportunity to offer proposals under Section 454.51(d) requirements.

13. The November 1, 2022 individual LSE IRP filings, along with their August 1, 2023 and December 1, 2023 procurement data filings, do not show LLT resources under contract to LSEs in sufficient quantities to achieve scale and cost reductions in the long run.

14. POUs are permitted by AB 1373 Water Code Sections 80820, 80822, and 80826 to opt in voluntarily to DWR centralized procurement.

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15. DWR is acting in the public interest and as a partner to the Commission and its LSEs in soliciting and contracting for LLT resources on behalf of all customers under the Commission’s IRP purview.

16. D.06-06-066, and several decisions augmenting it, cover generally-applicable confidentiality rules for contracts submitted before the Commission.

Conclusions of Law

1. AB 1373 authorizes the Commission to request that DWR conduct centralized procurement of certain eligible LLT resources, on behalf of customers of all LSEs under the Commission’s IRP purview.

2. By September 1, 2024, the Commission is required to make an initial need determination for centralized procurement by DWR.

3. A need determination, for purposes of AB 1373 should be defined as follows: the maximum value determined by the Commission to be procured by a CPE for a given resource type and/or resource attribute(s), on behalf of all LSEs under the Commission’s IRP purview.

4. For purposes of AB 1373, a “procurement request” should be defined as follows: after a need determination is made by the Commission, the Commission will send a procurement request to the CPE triggering the initiation of the procurement process.

5. If a need for LLT resources is found by the Commission, within six months after September 1, 2024, the Commission may make a request to DWR to exercise the centralized procurement mechanism outlined in AB 1373.

6. To make a need determination for the exercise of centralized procurement, AB 1373 codified as Section 454.52(a)(4), directs that the Commission “determine if there is a need for the procurement of eligible energy resources based on a review of the integrated resource plans submitted by load-serving entities in R.20-05-003 ALJ/JF2/jnf PROPOSED DECISION
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compliance with the requirements of this section and Section 454.53 and the progress towards meeting the portfolio of resources identified pursuant to subdivision (1) of Section 454.51.”

7. The Commission should reevaluate the need for centralized procurement of LLT resources in each IRP cycle, when considering the adoption of a PSP portfolio.

8. The need determinations made by the Commission for centralized procurement should be maximum amounts; DWR should be authorized to procure any amount from zero up to the maximum need determination, depending on the costs, value, and other factors of the bids received.

9. Resource diversity should be an explicit and important criterion for the selection of resources to be centrally procured.

10. Resources that are important to reducing the overall emissions in the electricity sector, but which may not compete favorably in price against other resources, should be considered for centralized procurement.

11. Market transformation of emerging technologies important to achieving GHG emissions goals in Section 454.53 should be an important purpose for selection of resources to be centrally procured.

12. DWR, at this time, should not be requested to conduct centralized procurement for technologies that are already widely commercially available.

13. Technologies that utilize fossil fuels to generate electricity are not eligible for centralized procurement by DWR according to Section 454.52(h)(1)(D).

14. The Commission should not, at this time, ask DWR to solicit for resource types that are already being widely procured in significant volumes by numerous individual LSEs.

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15. EGS should be defined based on the U.S. DOE definition in its “Enhanced Geothermal Shot” initiative.

16. LDES requested for DWR to solicit for centralized procurement should include 12+-hour LDES and multi-day LDES, but not lithium-ion batteries or PSH.

17. It is reasonable to ask DWR to solicit approximately half of the resource need identified in the most recent adopted PSP portfolio in D.24-02-047 for LDES and geothermal, in order to facilitate a downpayment on technologies necessary to achieve SB 100 goals, while still leaving room for LSEs to procure the technologies individually, after costs are reduced and market transformation is underway.

18. It is reasonable to ask DWR to solicit for 7.6 GW nameplate of OSW, which signals a strong interest in developing the resource, represents the level beyond which our staff cost-benefit analysis shows the potential for higher risks to ratepayers, is sufficient to foster cost savings as the resource is developed at scale, and avoids the potential for market power issues.

19. Centralized procurement of LLT resources should be considered by the Commission in a separate category from individual LSE procurement.

20. Any CPE procurement should not count toward the requirements of D.21-06-035, D.23-02-040, or D.24-02-047.

21. The Commission should evaluate in subsequent AB 1373 need determinations the LSE progress toward the D.21-06-035 requirements for procurement of 1 GW of high-capacity-factor clean LLT resources and consider whether additional CPE procurement of conventional geothermal resources is necessary.

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22. CPE procurement should be kept in a separate category for purposes of consideration of an RCPPP in the future in this proceeding.

23. AB 1373 does not provide an opportunity for LSEs to opt out of centralized procurement, once the Commission has made its need determination. LSEs subject to the Commission’s IRP purview should not be allowed to opt out of paying for their share of centralized procurement.

24. All benefiting LSE customers, under the provisions of Water Code Section 80821, will be subject to a nonbypassable charge, as determined by the Commission when any contracts are approved.

25. The burden of the investment costs for LLTs should not fall solely on the customers of LSEs under the Commission’s jurisdiction.

26. Costs and benefits of centralized procurement should be allocated annually by forecast energy load share for any energy-producing resources, including EGS and OSW.

27. Costs and benefits of centralized procurement should be allocated annually by forecast 12-month peak demand in each TAC area, and then further allocated to LSEs in the same manner as CAM resources, for any LDES capacity.

28. Further operational and implementation details of the allocation of costs and benefits of CPE procurement to LSEs will be handled in this proceeding or its successor before or during consideration of actual contracts to be signed by DWR.

29. It is not appropriate for DWR, as a partner agency, to file either an advice letter or an application before this Commission.

30. The consideration of any contracts recommended by DWR for execution should be brought to the Commission via a memorandum submitted by DWR in this proceeding or its successor and served on the service list.

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31. Subsequent to DWR’s memorandum, the assigned ALJ should initiate a separate phase of this proceeding or its successor to consider DWR’s recommended contracts for Commission approval, as well as their cost recovery.

32. Confidentiality provisions for any DWR contracts or potential contracts should follow generally established confidentiality rules emanating from D.06-06-066.

33. The Commission should recommend that DWR allow an option for bidders in each solicitation to provide open-book contract proposals.

34. Water Code Section 80820 requires that the Commission and DWR establish a procurement group to advise DWR on the solicitation process and results.

35. The Commission should recommend that DWR retain an expert consultant to advise on all aspects of the solicitation process and its results.

36. Representatives of LSEs should be allowed to participate as members of the procurement group as long as they are not directly involved in conducting solicitations for an LSE.

37. DWR should solicit procurement group members from affected community groups and Tribal Nations.

38. DWR should conduct a series of solicitations designed to contract for the resources determined to be needed in this decision, in a manner similar to the outline in Table 2 of this decision. DWR should keep the Commission and staff informed about the progress of solicitations and major milestones, via updates to the Executive Director, Energy Division, and the service list of this or a successor IRP rulemaking.

39. Commission staff should work closely with DWR on the preparation for and conduct of the resource solicitations recommended in this decision.

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40. The Commission should not need to render a second formal decision during the six-month window after September 1, 2024, and after any subsequent need determination in future IRP cycles. The request for procurement after the Commission’s formal need determination in a decision may come in the form of a letter to DWR from the Commission president and/or the assigned Commissioner to the IRP rulemaking, consistent with the provisions of this decision.

41. This proceeding should remain open.

O RDER
IT IS ORDERED that:

1. The Commission has evaluated eligible resource types under Public Utilities Code Section 454.52(h)(1)-(2) categories and has determined that there is a need for centralized procurement through competitive solicitations by the Department of Water Resources (DWR) as a Central Procurement Entity for the following resources, in nameplate capacity, with energy deliveries and/or capacity online between June 1, 2031 and June 1, 2037. DWR is not required to procure all of the below resources and may procure as little as zero, depending on the reasonableness of prices offered by developers:
(a) A maximum of 1,000 megawatts (MW) of Enhanced Geothermal Systems, as defined by the United States Department of Energy's “Enhanced Geothermal Shot” initiative;
(b) A maximum of 1,000 MW of long-duration energy storage (LDES) that can discharge for 12 hours or more that does not employ lithium-ion batteries or pumped storage hydroelectric (PSH) technologies; (c) A maximum of 1,000 MW of multi-day LDES that does not employ lithium-ion batteries or PSH technologies; and
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(d) A maximum of 7,600 MW of offshore wind.

2. The Commission recommends that the Department of Water Resources (DWR) undertake a series of solicitations for the resources identified in Ordering Paragraph 1 above, in a manner similar to that outlined in Table 2 of this decision. The Commission requests that DWR keep the Commission’s Executive Director, Energy Division, and the service list for this or a successor integrated resource planning rulemaking informed as to solicitation progress and major milestones.

3. All load-serving entities with obligations under the integrated resource planning process of the Commission related to Public Utilities Code Sections 454.51 and 454.52 shall be required to pay for their proportional share of any resources determined to be needed by the Commission and centrally procured by the Department of Water Resources for the life of the contracts, once approved by the Commission.

4. The costs and benefits of any procurement of offshore wind and enhanced geothermal systems shall be allocated annually on the basis of forecast energy load share, for the life of each contract.

5. The costs and benefits of any procurement of long-duration energy storage shall be allocated annually to each transmission access charge area based on forecast 12-month peak load, and then further allocated to each load-serving entity’s customers in the same manner as the Cost Allocation Mechanism adopted in Decision 06-07-029, for the life of each contract.

6. The Commission recommends that the Department of Water Resources seek commitments from any publicly-owned utilities that seek to opt in voluntarily to the centralized procurement of resources during the six-month period after the Commission makes its resource need determination.

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7. The Commission recommends that the Department of Water Resources retain an expert consultant to advise on all aspects of the design, conduct, and outcome of the competitive solicitations for long lead-time resources.

8. Representatives of load-serving entities (LSEs) shall be allowed to participate as members of the procurement group established in response to Water Code Section 80820 as long as they are not directly involved in conducting solicitations for an LSE.

9. The Commission recommends that the Department of Water Resources conduct outreach to and invite representatives from community groups and Tribal Nations affected by the resource developments contemplated in the competitive solicitations to serve on the procurement group referred established according to Water Code Section 80820.

10. The Department of Water Resources shall submit its recommended contracts to the Commission in the form of a memorandum (with confidential version as necessary) sent to the Commission and served on the service list for this proceeding or its successor.

11. Rulemaking 20-05-003 remains open.

This order is effective today.

Dated , at San Francisco, California

ADVICE LETTER

SUMMARY

ENERGY UTILITY
Company name/CPUC Utility No.:

Utility type:

Phone #:

EXPLANATION OF UTILITY TYPE

ELC GAS

PLC HEAT
MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Advice Letter (AL) #:

WATER
E-mail:

E-mail Disposition Notice to:

Contact Person:

ELC = Electric
PLC = Pipeline
GAS = Gas
HEAT = Heat WATER = Water
(Date Submitted / Received Stamp by CPUC)
Subject of AL:

Tier Designation:

Keywords (choose from CPUC listing):

AL Type: Monthly Quarterly Annual One-Time Other:

If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution #:

Does AL replace a withdrawn or rejected AL? If so, identify the prior AL:

Summarize differences between the AL and the prior withdrawn or rejected AL:

Confidential treatment requested? Yes No
If yes, specification of confidential information:

Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/ access to confidential information:

Resolution required? Yes No
Requested effective date: No. of tariff sheets:

Estimated system annual revenue effect (%):

Estimated system average rate effect (%):

When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting).

Tariff schedules affected:

Service affected and changes proposed1:

Pending advice letters that revise the same tariff sheets:
1 Discuss in AL if more space is needed.

California Public Utilities Commission
California Public Utilities Commission
Energy Division Tariff Unit Email:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

Contact Name:

Title:

Utility/Entity Name:

Telephone (xxx) xxx-xxxx:

Facsimile (xxx) xxx-xxxx:

Email:

CPUC
Energy Division Tariff Unit
505 Van Ness Avenue
San Francisco, CA 94102
ENERGY Advice Letter Keywords
Affiliate Direct Access Preliminary Statement
Agreements Disconnect Service Procurement
Agriculture ECAC / Energy Cost Adjustment Qualifying Facility Avoided Cost EOR / Enhanced Oil Recovery Rebates
Balancing Account Energy Charge Refunds
Baseline Energy Efficiency Reliability
Bilingual Establish Service Re-MAT/Bio-MAT
Billings Expand Service Area Revenue Allocation
Bioenergy Forms Rule 21
Brokerage Fees Franchise Fee / User Tax Rules
CARE G.O. 131-D Section 851
CPUC Reimbursement Fee GRC / General Rate Case Self Generation Capacity Hazardous Waste Service Area Map
Cogeneration Increase Rates Service Outage
Compliance Interruptible Service Solar
Conditions of Service Interutility Transportation Standby Service Connection LIEE / Low-Income Energy Efficiency Storage
Conservation LIRA / Low-Income Ratepayer Assistance Street Lights Consolidate Tariffs Late Payment Charge Surcharges
Contracts Line Extensions Tariffs
Core Memorandum Account Taxes
Credit Metered Energy Efficiency Text Changes
Curtailable Service Metering Transformer
Customer Charge Mobile Home Parks Transition Cost
Customer Owned Generation Name Change Transmission Lines Decrease Rates Non-Core Transportation Electrification
Demand Charge Non-firm Service Contracts Transportation Rates Demand Side Fund Nuclear Undergrounding
Demand Side Management Oil Pipelines Voltage Discount
Demand Side Response PBR / Performance Based Ratemaking Wind Power Deposits Portfolio Withdrawal of Service
Depreciation Power Lines
MCE Advice Letter 79-E
1 July 8, 2024
California Public Utilities Commission
Energy Division
Attention: Tariff Unit
505 Van Ness Avenue, 4th Floor
San Francisco, CA 94102-3298
MCE Supplemental Advice Letter 79-E-A
RE: Supplemental: 2025 Budget Request and Marketing, Education and Outreach Plan for the Disadvantaged Communities Green Tariff Program