Agenda packet — MCE Board of Directors, July 17, 2025

MCE Board of Directors Meeting
Thursday, July 17, 2025
6:30 p.m.
1125 Tamalpais Avenue, San Rafael, CA 94901
2300 Clayton Road, Suite 1500, Concord, CA 94520
955 School Street, Napa, CA 94559, City Hall Committee Room (City of Napa) 675 Texas Street, Fairfield, CA 94533, First Floor Hearing Room (County of Solano) Public comments may be made in person or remotely via the details below.

Remote Public Meeting Participation
Video Conference: https://zoomto.me/F6Ogt
Phone: Dial (669) 900-9128, Meeting ID: 890 0487 7785, Passcode: 525690 Materials related to this agenda are available for physical inspection at MCE’s offices in San Rafael at 1125 Tamalpais Ave, San Rafael, CA 94901.

DISABLED ACCOMMODATION: If you are a person with a disability who requires an accommodation or an alternative format, please contact MCE at (888) 632-3674 or [email protected] at least 72 hours before the meeting start time to ensure arrangements are made.

Agenda Page 1 of 2

1. Roll Call/Quorum

2. Board Announcements (Discussion)

3. Public Open Time (Discussion)

4. Report from Chief Executive Officer (Discussion)

5. Consent Calendar (Discussion/Action)
C.1. Approval of 5.15.25 Meeting Minutes
C.2. Approved Contracts for Energy Update
Agenda Page 2 of 2
C.3 Proposed Resolution No. 2025-03 Establishing the Date, Time, and Location of Regular Board Meetings
C.4 Proposed MCE Policy 019 – Disposition of Surplus Property C.5 Adoption of Revised MCE Load Management Standards Plan C.6 Proposed Resolution 2025-04 Authorizing the CEO to Negotiate and Execute Vendor Services Agreements with Community
Energy and Equity Resources LLC, Serious Controls LLC, and Lawrence Berkeley National Laboratory for MCE’s Virtual Power Plant Program Supported by Funding from the California Energy Commission

6. MCE 24x7 Renewable Energy Pilot Proposal (Discussion/Action)

7. Update of Deep Green Premium Proposed Effective Date October 1, 2025 (Discussion/Action)

8. Customer Operations Update (Discussion)

9. Board & Staff Matters (Discussion)

10. Adjourn
The Board of Directors may discuss and/or take action on any or all of the items listed on the agenda irrespective of how the items are described.

DRAFT

MCE BOARD MEETING MINUTES
Thursday, May 15, 2025
6:30 P.M.

Present: Liz Alessio, The County of Napa and Four Napa Cities/Town (American Canyon, Calistoga, St. Helena, and Yountville) Stephanie Andre, City of Larkspur
Dion Bailey, City of Hercules
Eli Beckman, Town of Corte Madera
Mark Belotz, Town of Danville
Monica Brown, County of Solano
Barbara Coler, Town of Fairfax
Cindy Darling, City of Walnut Creek
Kevin Jacobs, City of Novato
Maika Llorens-Gulati, City of San Rafael
Aaron Meadows, City of Oakley, joined at 6:35pm
Laura Nakamura, City of Concord
Beth Painter, City of Napa
Max Perrey, City of Mill Valley
Gabe Quinto, City of El Cerrito
Mary Sackett, County of Marin
Shanelle Scales-Preston, County of Contra Costa
Amanda Szakats, City of Pleasant Hill, joined at 6:42pm Graham Thiel, Town of Moraga, joined at 6:39pm
Holli Thier, Town of Tiburon, joined at 7:05pm
Sridhar Verose, City of San Ramon
Sally Wilkinson, City of Belvedere, joined at 6:47pm
Cesar Zepeda, City of Richmond
Brianne Zorn, City of Martinez

Absent: Kari Birdseye, City of Benicia
Gina Dawson, City of Lafayette
C. William Kircher, Town of Ross
Arlene Kobata, City of Pittsburg
Tarrell Kullaway, Town of San Anselmo
Devin Murphy, City of Pinole
Elizabeth Pabon-Alvarado, City of San Pablo
Charles Palmares, City of Vallejo
Manveer Sandhu, City of Fairfield
Steven Woodside, City of Sausalito
DRAFT
Staff
& Others: Jared Blanton, VP of Public Affairs
Jesica Brooks, Lead Board Clerk and Executive Assistant Alice Havenar-Daughton, VP of Customer Programs
Vicken Kasarjian, Chief Operating Officer
Caroline Lavenue, Legal Counsel II
Tanya Lomas, Board Clerk Associate
Alexandra McGee, VP of Strategic Initiatives
Catalina Murphy, General Counsel
Ashley Muth, Internal Operations Coordinator
Justine Parmelee, VP of Internal Operations
Mike Rodriguez-Vargas, Internal Operations Assistant
Enyonam Senyo-Mensah, Internal Operations Manager
Dan Settlemyer, Internal Operations Associate
Dawn Weisz, Chief Executive Officer

1. Roll Call
Chair Scales-Preston called the regular meeting to order at 6:31 p.m. with quorum established by roll call.

2. Board Announcements (Discussion)
Chair Scales-Preston opened the floor for board announcements, and there were no comments.

3. Public Open Time (Discussion)
Chair Scales-Preston opened the public comment period and there were comments made by member of the public Rebekah Collins.

4. Report from Chief Executive Officer (Discussion)
CEO Weisz introduced this item and addressed questions from Board members.

Chair Scales-Preston opened the public comment period and there were no comments.

5. Consent Calendar (Discussion/Action)
C.1 Approval of 4.17.25 Meeting Minutes
C.2 Approved Contracts for Energy Update
C.3 Addition of Board Members to Committees
DRAFT
Chair Scales-Preston opened the public comment period and there were no comments.

6. Customer Programs Update (Discussion)
Alice Havenar-Daughton, VP of Customer Programs, presented this item and addressed questions from Board members.

Chair Scales-Preston opened the public comment period and there were no comments.

Action: No action required.

7. Public Affairs Update (Discussion)
Jared Blanton, VP of Public Affairs, presented this item and addressed questions from Board members.

Chair Scales-Preston opened the public comment period and there were no comments.

Action: No action required.

8. Strategic Initiatives Update (Discussion)
Alexandra McGee, VP of Strategic initiatives, presented this item and addressed questions from Board members.

Chair Scales-Preston opened the public comment period and there were no comments.

Action: No action required.

9. Board & Staff Matters (Discussion)
There were no comments.

10. Adjournment
Chair Scales-Preston adjourned the meeting at 8:12 p.m. to the next scheduled Board Meeting on June 19, 2025.

Action: It was M/S/C (Meadows/Darling) to approve Consent Calendar items C.1, C.2, and C.3. Motion carried by unanimous roll call vote. (Absent: Birdseye, Dawson, Kircher, Kobata, Kullaway, Murphy, Pabon-Alvarado, Palmares, Sandhu, Thier, Woodside).

DRAFT
___________________________________________
Shanelle Scales-Preston, Chair
Attest:
___________________________________________
Dawn Weisz, Secretary
July 17, 2025
TO: MCE Board of Directors
FROM: Adita Farahiyah, Power Resources Analyst
RE: Approved Contracts for Energy Update (Agenda Item #05 C.2) Dear Board Members:

Summary:

This report summarizes contracts for energy procurement entered into by the Chief Executive Officer or her delegate and, if applicable, the Chair of the Technical Committee, since the last report was prepared for the regular Board meeting in May 2025. This summary is provided to your Board for information purposes only and no action is needed.

Review of Procurement Authorities:

In November 2020, your Board adopted Resolution 2020-04 which included the following provisions:

The CEO and Technical Committee Chair, jointly, are hereby authorized, after consultation with the appropriate Committee of the Board of Directors, to approve and execute contracts for Energy Procurement for terms of less than or equal to five years.

The CEO shall timely report to the Board of Directors all such executed contracts.

The CEO is authorized to approve and execute contracts for Energy Procurement for terms of less than or equal to 12 months, which the CEO shall timely report to the Board of Directors.

The CEO is required to report all such contracts and agreements to the MCE Board of Directors on a regular basis.

Item # Month of
Execution
Purpose Average Annual
Contract Amount
Contract
Term
1 April 2025 Sale of Resource Adequacy $933,750 1 Year or less 2 May 2025 Sale of Resource Adequacy $401,760 1 Year or less 3 May 2025 Purchase of Resource Adequacy $168,000 1 Year or less 4 May 2025 Sale of Import Allocation Rights $189,535.50 1 Year or less 5 June 2025 Sale of Resource Adequacy $225,000 1 Year or less Contract Approval Process:

Contract Approval Process: Energy procurement is governed by MCE’s Energy Risk Management Policy as well as Board Resolutions 2020-04 and 2018-08. The Energy Risk Management Policy (Policy) has been developed to help ensure that MCE achieves its mission and adheres to its procurement policies established by the MCE Board of Directors (Board), power supply and related contract commitments, good utility practice, and all applicable laws and regulations. The Board Resolutions direct the CEO to sign energy contracts up to and including 12 months in length.

The evaluation of every new energy contract is based upon how to best fill MCE’s open position. Factors such as volume, notional value, type of product, price, term, collateral threshold and posting, and payment are all considered before execution of the agreement.

After evaluation and prior to finalizing any energy contract for execution, an approval matrix is implemented whereby the draft contract is routed to key support staff and consultants for review, input, and approval. Typically, contracts are routed for commercial, technical, legal, and financial approval, and are then typically routed through the Chief Operating Officer for approval prior to execution. The table below is an example of MCE staff and consultants who may be assigned to review and consider approval prior to the execution of a new energy contract or agreement.

Review Owner Review Category
Vidhi Chawla (MCE, Vice President of Power Resources) Procurement/Commercial John Dalessi (Pacific Energy Advisors) Technical Review Steve Hall (Hall Energy Law) Legal
Nathaniel Malcolm (MCE, Senior Commercial Counsel) Legal/CPUC Compliance Maira Strauss (MCE, Vice President of Finance) Credit/Financial Vicken Kasarjian (MCE, Chief Operating Officer) Executive Fiscal Impacts:

Expenses and revenue associated with these Contracts and Agreements that are expected to occur during FY 2025/26 are within the FY 2025/26 Operating Fund Budget. Expenses and revenue associated with future years will be incorporated into budget planning as appropriate.

Recommendation:

Information only. No action required.

July 17, 2025
TO: MCE Board of Directors
FROM: Caroline Lavenue, Legal Counsel
Catalina Murphy, General Counsel
RE: Proposed Resolution No. 2025-03 Establishing the Date, Time, and Location of Regular Board Meetings (Agenda Item #05 C.3) ATTACHMENT: Resolution No. 2025-03 Establishing the Date, Time, and Location of Regular Board Meetings
Dear Board Members:

Summary:

MCE’s Concord office location is changing from Suite 1150 to Suite 1500 at 2300 Clayton Road. This is a resolution that would formally establish the new regular Board meeting location.

Background
Pursuant to Section 4.12 of the MCE Joint Powers Agreement and Section 54954(a) of the California Government Code Section, MCE must provide by ordinance or resolution, the date, time, and place for holding regular meetings.

On November 16, 2023, the Board of Directors adopted Resolution No. 2023-13 which established the current date, time and location of MCE’s regular Board meetings.

Because MCE’s office location is changing from Suite 1150 to Suite 1500, MCE has prepared the attached Resolution 2025-03 Establishing the Date, Time, and Location of Regular Board Meetings which sets forth the updated suite number.

Fiscal Impacts:

None.

Recommendation:

Adopt Proposed Resolution No. 2025-03 Establishing the Date, Time, and Location of Regular Board Meetings.

RESOLUTION NO. 2025-03

A RESOLUTION OF THE BOARD OF DIRECTORS OF

MARIN CLEAN ENERGY ESTABLISHING THE DATE, TIME,

AND LOCATION OF REGULAR BOARD MEETINGS
WHEREAS, Marin Clean Energy (MCE) is a joint powers authority established on December 19, 2008, and organized under the Joint Exercise of Powers Act (Government Code Section 6500 et seq.); and
WHEREAS, MCE members include the following communities: the County of Marin, the County of Contra Costa, the County of Napa, the County of Solano, the City of American Canyon, the City of Belvedere, the City of Benicia, the City of Calistoga, the City of Concord, the Town of Corte Madera, the Town of Danville, the City of El Cerrito, the Town of Fairfax, the City of Fairfield, the City of Hercules, the City of Lafayette, the City of Larkspur, the City of Martinez, the City of Mill Valley, the Town of Moraga, the City of Napa, the City of Novato, the City of Oakley, the City of Pinole, the City of Pittsburg, the City of Pleasant Hill, the City of San Ramon, the City of Richmond, the Town of Ross, the Town of San Anselmo, the City of San Pablo, the City of San Rafael, the City of Sausalito, the City of St. Helena, the Town of Tiburon, the City of Vallejo, the City of Walnut Creek, and the Town of Yountville; and
WHEREAS, the California Government Code Section 54954(a) requires the legislative body of a local agency to "provide by ordinance, resolution, bylaws, or by whatever other rule is required for the conduct of business by that body, the time and place for holding regular meetings"; and
WHEREAS, Section 4.12 of the MCE Joint Powers Agreement provides that the Board shall establish by ordinance or resolution “the date, hour, and place of each regular meeting”; and
WHEREAS, in Resolution 2023-13, MCE established that regular meetings of the Board of Directors of MCE be held on the third Thursday of each month beginning at 6:30 p.m. at the MCE Charles F. McGlashan Board Room, 1125 Tamalpais Avenue, San Rafael, CA 94901; and the MCE Mt. Diablo Room, 2300 Clayton Road, Suite 1150, Concord, CA 94520, or as otherwise designated in the meeting agenda; and WHEREAS, MCE’s Board of Directors desires to modify the location of the regular Board of Directors meeting at the Concord location from Suite 1150 to Suite 1500.

NOW, THEREFORE, BE IT RESOLVED, by the MCE Board of Directors, that the regular meetings of the Board of Directors of MCE shall be held on the third Thursday of each month beginning at 6:30 p.m. at the MCE Charles F. McGlashan Board Room, 1125 Tamalpais Avenue, San Rafael, CA 94901; and at 2300 Clayton Road, Suite 1500, Concord, CA 94520, or as otherwise designated in the meeting agenda.

PASSED AND ADOPTED at a regular meeting of the MCE Board of Directors on this 17th day of July, 2025, by the following vote:

AYES NOES ABSTAIN ABSENT
County of Marin
Contra Costa County
County of Napa
County of Solano
City of American Canyon
City of Belvedere
City of Benicia
City of Calistoga
City of Concord
Town of Corte Madera
Town of Danville
City of El Cerrito
Town of Fairfax
City of Fairfield
City of Hercules
City of Lafayette
City of Larkspur
City of Martinez
City of Mill Valley
Town of Moraga
City of Napa
City of Novato
City of Oakley
City of Pinole
City of Pittsburg
City of Pleasant Hill
City of San Ramon
City of Richmond
Town of Ross
Town of San Anselmo
City of San Pablo
City of San Rafael
City of Sausalito
City of St. Helena
Town of Tiburon
City of Vallejo
City of Walnut Creek
Town of Yountville
______________________________________

CHAIR, MCE
Attest:
___________________________________________

SECRETARY, MCE
July 17, 2025
TO: MCE Board of Directors
FROM: Caroline Lavenue, Legal Counsel
Catalina Murphy, General Counsel
RE: Proposed MCE Policy 019 – Disposition of Surplus Property (Agenda Item #05 C.4)
ATTACHMENT: MCE Policy 019 – Disposition of Surplus Property Dear Board Members:

Summary:

The proposed MCE Policy 019 - Disposition of Surplus Property (“Policy 019”) would establish procedures for the identification, valuation and disposition of surplus personal property owned by MCE. As proposed, Policy 019 delegates certain authority to the Purchasing Agent and outlines priority recipients and disposition methods. MCE’s Chief Executive Officer is the Purchasing Agent for MCE as designated by your Board in 2018 via Resolution 2018-04.

Background:

With MCE’s Concord office suite change, furniture that was not able to fit in the new suite or repurposed at MCE’s San Rafael office, is no longer required for public use. Policy 019 would allow MCE to dispose of any of the remaining furniture deemed surplus property and reduce offsite storage fees currently hosting the property.

Delegated Authority and Valuation of Property
Policy 019 authorizes the Purchasing Agent to (i) determine whether personal property is surplus, (ii) identify the value of the property based on the book value reflected in MCE’s standard asset depreciation schedules, (iii) establish the public purpose to dispose of the surplus property, and (iv) dispose of the surplus property per the disposition methods of Policy 019. The Purchasing Agent will use the most economic means when it comes to the disposition of the surplus property.

Priorities for Disposition via Donation
If the surplus property has no resale market and an aggregate value of $10,000 or less, then the Purchasing Agent may donate the surplus property to the eligible entities listed below in the following order:

1. Local Government entities within MCE’s service area.

2. Nonprofit organizations within MCE’s service area.

3. Entities located geographically near the surplus property.

Public Sale Option
When surplus property is valued at more than $10,000, the Purchasing Agent may conduct a public sale at MCE’s offices or other location deemed appropriate by the Purchasing Agent by posting a notice at MCE’s office and providing general notice to the surrounding area.

Fiscal Impacts:

If approved, the Policy would reduce storage costs and potentially generate modest revenue from the sale of unneeded property.

Recommendation:

Approve MCE Policy 019 – Disposition of Surplus Property.

MCE Policy 019 - Disposition of Surplus Property
Pursuant to California Government Code, § 25504 and § 6509, the Purchasing Agent has the authority to sell directly, lease, donate or otherwise dispose of any fixed asset property belonging to the agency that is determined by the purchasing agent to be no longer required for public use. Fixed asset property is deemed no longer required for public use when such property is transferred to the Purchasing Agent as surplus property and is not claimed by any other agency department for use.

A. If the Purchasing Agent determines, based on the book value reflected in MCE’s standard asset depreciation schedules, that the aggregate value of the property is $10,000 or less and there is no market for such property, it may be donated upon a finding by the Purchasing Agent that the donation serves the public interest in the following order of preference:
i. To public entities, including the State of California, counties, cities or special districts within MCE’s service area.
ii. To nonprofit corporations that have been certified as such by the Commissioner of Internal Revenue, that have filed requests with the purchasing agent for surplus property, and that are located within MCE’s service area. iii. To any other entity located in close proximity to the storage location of the surplus property, for the purpose of reducing greenhouse gas emissions from transport.

B. If the Purchasing Agent determines, based on the book value reflected in MCE’s standard asset depreciation schedules, that the aggregate value of the property is more than $10,000 and there is a market for such property, the Purchasing Agent may authorize a public sale.

Such sale may be conducted in a format consistent with a community sale (e.g., a garage sale), and shall be publicly noticed by posting information at MCE’s offices and providing notice to neighboring entities within the vicinity of the surplus property location. Items shall be priced in a manner that reflects fair market value or nominal value as deemed appropriate by the Purchasing Agent.
i. Any proceeds from the sale or lease of surplus fixed asset property shall be paid into MCE’s Operating Fund.

July 17, 2025
TO: MCE Board of Directors
FROM: Sabrinna Soldavini, Vice President of Policy
Jordyn Bishop, Senior Policy Analyst
RE: Adoption of Revised MCE Load Management Standards Plan (Agenda Item #05 C.5)
ATTACHMENT: A. Clean – Revised MCE Load Management Standards Plan B. Redline – Revised MCE Load Management Standards Plan Dear Board Members:

Summary:

Staff recommends your Board adopt MCE’s Revised Load Management Standards Plan (“Revised Plan”) and authorize Staff to submit the Revised Plan, including any necessary revisions that align with the Board direction, to the California Energy Commission (“CEC”).

Background:

In April 2023, the CEC’s revised Load Management Standards (“LMS”) took effect. The LMS are intended to encourage automated load-shifting of electricity to off-peak hours. The LMS request that Load Serving Entities (“LSEs”) submit to its Board a plan outlining how it intends to meet the goals of the LMS, and upon Board approval, submit the adopted plan to the CEC Executive Director for review. On May 16, 2024, your Board approved MCE’s Load Management Standards Plan (“LMS Plan”) and on June 14, 2024, Staff submitted the LMS Plan to the CEC.

The LMS states that the CEC’s Executive Director shall review plans, make an initial determination whether the plan is consistent with the LMS, and either return them to the LSE for recommended changes or submit them to the Commission for review and potential approval. On June 19, 2025, the CEC’s Executive Director sent a letter to MCE determining that MCE’s LMS Plan is consistent with the LMS, with one exception for which CEC staff is recommending minor plan revisions.

On April 4, 2025, the Technical Committee approved MCE’s participation in the Hourly Flex Pricing Pilots authorized by the California Public Utilities Commission (“CPUC”) in PG&E’s service area. Accordingly, the CEC’s June 19 letter requests that MCE modify its LMS Plan to reflect its Board’s decision to offer these dynamic rate pilots. The attached Revised LMS Plan includes the respective minor redline edits to Section 4.2 – Dynamic Rates Evaluation, and Section 4.3 – Dynamic Rate Development and Application Plan.

The LMS also requests that all regulated LSEs work together to develop a plan for a single statewide standard tool for authorized rate data access by third parties. On October 1, 2024, the joint LSEs including MCE submitted a proposed plan for the Single Statewide RIN Access Tool. The CEC’s June 19 letter also requests that MCE modify its LMS Plan to reflect this submission. The attached Revised LMS Plan includes the respective minor redline edits to Section 3.3 – Plans and Current Participation in the Development of Single Statewide RIN Access Tool.

MCE’s original LMS Plan was adopted by your Board in May 2024. The CEC’s recommended revisions are incorporated into the attached Revised LMS Plan, but no additional updates are being made at this time. A full LMS Plan update will be completed in the future to align the plan with current conditions.

Fiscal Impacts:

There are no immediate fiscal impacts associated with the adoption of MCE’s Revised LMS Plan.

Recommendation:

Adopt and authorize Staff to submit the Revised Plan, including any necessary revisions that align with the Board direction, to the CEC.
1 MARIN CLEAN ENERGY

LOAD MANAGEMENT STANDARDS PLAN

Approved by MCE Board May 16, 2024

2 1 Table of Contents
1 Table of Contents 2
2 Introduction 3

2.1 About MCE 3

2.2 Load Management Standards 4

2.2.1 MCE LMS Plan and Board Authority 5
3 Access to Price Signals 8

3.1 Time-Dependent Rate Submission to MIDAS 8

3.1.1 Existing Rates Upload 8

3.1.2 Future Rates Upload 9

3.2 Plan to Provide Rate Identification Number(s) on Customer Billing Statements and Online Account Using Both Text and QR Code 9

3.3 Plans and Current Participation in the Development of Single Statewide RIN Access Tool – Amended July 2025 10
4 MCE Rates and Dynamic Rate Considerations 10

4.1 Overview of MCE’s Current Time-Dependent Rate Offerings 11

4.2 Dynamic Rates Evaluation – Amended July 2025 15

4.3 Dynamic Rate Development and Application Plan – Amended July 2025 20 5 Load Flexibility Programs 21

5.1 Overview of MCE Load Flexibility Programs 21

5.2 Evaluation of Programs 23

5.2.1 Cost Effectiveness 24

5.2.2 Equity 25

5.2.3 Technological Feasibility 25

5.2.4 Benefits to the Grid and Customers 26
6 Public Information Program 27
7 Appendix 29

3 2 Introduction

2.1 About MCE
Marin Clean Energy (“MCE”) is California’s first Community Choice Aggregation (“CCA”) Program, a not-for-profit Joint Powers Authority (“JPA”) that began serving customers in 2010.

MCE’s mission is to confront the climate crisis by eliminating fossil fuel greenhouse gas (“GHG”) emissions, producing renewable energy, and creating equitable community benefits. MCE’s vision is to lead California to an equitable, clean, affordable, and reliable energy economy by serving as a model for community-based renewable energy, energy efficiency, and cutting-edge clean-tech products and programs.

As a load-serving entity (“LSE”) MCE provides electricity generation service to approximately 580,000 customer accounts. These accounts represent more than one million residents and businesses across four Bay Area counties.1 MCE procures for annual retail sales of approximately 5,729 GWh and a peak load of more than 1,240 MW.

MCE provides service to approximately 87 percent of eligible customers within its service area, which is depicted below in Figure 1. MCE is also the default generation provider for any new or relocated customers therein.

Figure 1: MCE Service Area Map
1 MCE serves communities across Contra Costa, Marin, Napa, and Solano counties. Those communities currently receiving service include: Unincorporated Contra Costa, Marin, Napa, and Solano counties and the Cities and Towns of Concord, Danville, El Cerrito, Lafayette, Martinez, Moraga, Oakley, Pinole, Pittsburg, Pleasant Hill, Richmond, San Pablo, San Ramon, Walnut Creek, Belvedere, Corte Madera, Fairfax, Larkspur, Mill Valley, Novato, Ross, San Anselmo, San Rafael, Sausalito, Tiburon, American Canyon, Calistoga, Napa, St. Helena, Yountville, Benicia, Vallejo, and Fairfield. MCE expects service to expand to include the City of Hercules in April of 2025. 4 As a JPA and local government agency, MCE is governed by a 34-member Board of Directors (“Board” or “Governing Board”) composed of elected representatives from MCE’s member communities. MCE’s Board sets policy for the agency and oversees operations, including rates and procurement planning. Through these representatives, MCE is controlled by and accountable to the communities MCE serves.

MCE was formed to empower its member communities to choose the generation resources that reflect their specific values and needs. As a mission-driven local government agency, MCE works toward the following:
● Reducing GHG emissions and accelerating the supply of clean energy being delivered to and used on the grid;
● Developing community programs and local energy projects to expand access to competitively priced renewable energy and energy efficiency programs for all customers; ● Creating economic and workforce benefits associated with renewable energy and energy conservation programs; and
● Leveraging energy and conservation spending to promote more equity throughout MCE’s communities and California.

2.2 Load Management Standards
In Docket Number 21-OIR-03 the California Energy Commission (“CEC”) adopted Revised Load Management Standards (“LMS” or “Standards”). The amendments to the LMS, which became effective on April 1, 2023, are intended to form the foundation for a statewide system of time and locational dependent signals that can be used by automation-enabled devices to encourage load flexibility on the electric grid. Simply, the Standards are intended to encourage automated load shifting of electricity to off-peak hours.

To accomplish the goals of the LMS, the regulations request California’s large CCAs,2 investor-owned utilities (“IOUs”), and large publicly owned utilities (“POUs”) to offer customers access to rate-structures and/or programs that allow automated responses to prices or other grid signals to manage and optimize their energy use.

Specifically, the LMS request large CCAs to (1) develop and propose marginal cost-based rates that vary at least hourly3
or, (2) if the Board finds that implementing marginal cost-based hourly rates would not materially reduce peak load, be technologically feasible, and/or be cost-effective, offer a load flexibility program that allows at least one option for automating response to the CEC’s Market Informed Demand Automation Server (“MIDAS”) signals for customer classes where MCE’s Board determines such a program would materially reduce peak load and be cost-effective. For the purposes of this plan, MCE will refer to marginal cost-based rates that vary at least hourly as defined in the LMS as “hourly” or “dynamic” rates. 2 The LMS define Large CCAs as any CCA that provides in excess 700 GWh of electricity to customers in any calendar year. 3Section 1623.1(b)(1) of the LMS define a marginal cost-based rate as the sum of the marginal energy cost, the marginal capacity cost (generation, transmission, and distribution), and any other appropriate time and location dependent marginal costs, including the locational marginal cost of associated greenhouse gas emissions, on a time interval of no more than one hour.
5 2.2.1 MCE LMS Plan and Board Authority
Section 1623.1(a) requests each large CCA submit a plan outlining how it plans to meet the objectives of the LMS to its Board by April 1, 2024.

As a large CCA that shares the goals and objectives of the LMS to better align demand of electricity with periods of high renewable energy supply and encouraging automated load shifting away from peak periods, MCE submits this plan to the Board for approval. 4 The purpose
of this plan is to identify the steps and activities MCE plans to voluntarily undertake which align with the goals of the LMS.

MCE notes that nothing in this plan overrides or supersedes MCE’s Board’s sole authority as the governing and rate-making body of MCE.5 Nothing in this plan implies any jurisdictional authority of the CEC over MCE’s rates and rate programs. MCE is currently voluntarily taking reasonable steps that meet the standards within the LMS regulations.

Additionally, as outlined in the LMS, MCE’s Board may approve a plan, or material revisions to a previously approved plan, that delays implementation of or modifies the goals of LMS Subsections 1623.1(b)-(c), if the Board determines that despite good faith efforts implantation:
● Would result in extreme hardship to MCE;
● Would result in reduced system reliability (e.g., equity or safety) or efficiency; ● Would not be technologically feasible or cost effective; or ● Must be modified to provide a more technologically feasible, equitable, safe, or cost-effective way to achieve the LMS or plan’s goals.

Accordingly, MCE submits this plan to the Board for adoption and approval to implement as outlined herein. Table 1 below provides a list of each regulatory standard or goal as outlined in the LMS and MCE’s plan to meet that standard or goal at the time of this writing. As described, MCE plans to continue to offer its portfolio of current and planned load flexibility programs and time dependent rates aimed at encouraging customers to use energy in off-peak hours, and will continue to explore how it may offer new cost-effective dynamic rates, pilots, and load flexibility programs that materially reduce peak load, encourage load control through automation, and provide reliability and environmental benefits for MCE customers and the California electric grid. 4 Consistent with Section 1623.1(a) of the LMS, MCE submitted this plan to its Board on March 29, 2024, and will submit this plan to the CEC within 30 days of Board approval. 5 Public Utilities Code Section 366.2(c)(3) provides that CCAs retain jurisdiction for setting rates for the electricity they purchase on behalf of their communities.
6 Table 1: MCE LMS Roadmap
Load Management
Standards Section Standard Description Target Date MCE Adopted Plan to Meet Standard §1623.1(c)
Upload existing time-dependent rates to
MIDAS database.

July 1, 2023
Status: Achieved
MCE plans to maintain future rates in
MIDAS to the extent it is cost
effective and technologically feasible.

MCE cannot confirm that uploading
future dynamic rates or programs to
MIDAS will be cost effective or
technologically feasible.
§1623.1(a)(1)
Develop and submit a
plan for adoption to
MCE’s Board addressing
how MCE plans to meet
objectives of the LMS.

The plan is to be
considered for adoption
by MCE’s Board within 60
days of submission at a
duly noticed public
meeting.

April 1, 2024 Status: Achieved
§1623.1(a)(3)(A)
Within 30 days of
adoption of the plan,
submit the plan to the
CEC’s Executive Director.
30 Days After
Board
Adoption
Status: MCE will submit this plan to
the CEC within 30 days of Board
adoption.
§1623(c)
Within one year of LMS
effective date, provide
customers access to their
Rate Identification
Numbers on billing
statements and in online
accounts using both text
and quick response code
format.

April 1, 2024
Status: In Progress, Expected to
Achieve
§1623(c)
In conjunction with the
other named LSEs,
develop and submit to the
CEC a plan for a single
statewide standard tool
for authorized rate data
access by third parties
and the terms and
conditions for using the
tool. Upon CEC approval,
maintain and implement
the tool.

October 1,
2024
Status: In Progress
MCE is engaged in and monitoring
the development process for the
single statewide tool.
7 Load Management
Standards Section Standard Description Target Date MCE Adopted Plan to Meet Standard §1623.1(b)(3)
Submit to the CEC a list of
load flexibility programs
deemed cost effective by
MCE. The portfolio of
programs should provide
at least one option to
automate response to
MIDAS signals for each
customer class where
MCE’s Board has
determined such a
program would materially
reduce peak load.

October 1,
2024
Status: In Progress
MCE cannot determine that such a
program will materially reduce peak
load for any customer class. MCE will
submit a list of programs deemed
cost effective to the CEC but does
not expect to include an option to
automate response to MIDAS signal
at this time.
§1623.1(a)(3)(C)
Submit annual reports to
the CEC demonstrating
implementation of the
plan, as approved by the
Board.

Annually
Status: In Progress
MCE will submit annual reports
beginning one year after the
adoption of this plan.
§1623.1(b)(2)
Submit at least one
marginal cost-based rate
to MCE’s Board for
approval for any customer
class(es) where such a rate
will materially reduce peak
load. An Information copy
of the tariff applications
will be provided to the
CEC.

July 1, 2025
Status: In Progress
At this time MCE cannot determine
that such a rate or will provide
material, incremental reductions to
peak load or be cost effective for any
customer class.

However, MCE is interested in
collecting the data necessary to make
such determinations and will continue
to explore options to offer dynamic
rate pilots in its service territory. MCE
therefore recommends the Board
modify this standard and determine
that MCE may, but is not required to,
propose such a rate or program by
the target date.

MCE will continue to evaluate and
address in its next plan iteration and
any annual reports.
§1623.1(b)(4)
Offer each customer
voluntary participation in
either a marginal cost-based rate, if approved by
the Board, or a cost-effective load flexibility
program.

July 1, 2027
Status: To be determined by future
Board direction.

MCE notes that this target date is
after the next review of MCE’s LMS is
expected to be completed. As such,
MCE will likely provide an update in
its next LMS plan as appropriate.
8 Load Management
Standards Section Standard Description Target Date MCE Adopted Plan to Meet Standard §1623.1(b)(5)
Conduct a public
information program to
inform and educate
affected customers on
why marginal cost-based
rates or load flexibility
programs and automation
are needed, how they will
be used, and how these
rates and programs can
save customers money.

No Target
Date Specified
Status: To be determined by future
Board direction and future adoption
of dynamic rates or load-modifying
programs.
§1623.1(a)(1)(C)
Review the plan at least
once every three years
after the plan is adopted
and submit a plan update
to the Board if there is a
material change.

Once Every
Three Years
Status: MCE will review its LMS plan
at least once every three years
following the date of adoption.
3 Access to Price Signals

3.1 Time-Dependent Rate Submission to MIDAS
Adopted LMS Amendments Section 1623.1(c) requests each Large CCA upload existing time dependent rates to the MIDAS database by July 1, 2023. On June 1, 2023, the CEC issued Order No. 23-0531-109 approving an extension for CCAs to upload time-dependent generation rates by August 1, 2023, and any remaining time-depending rates with rate modifiers by October 1, 2023. Large CCAs are also asked to upload any new time-dependent rates or changes to existing rates, prior to the effective date of that rate.

3.1.1 Existing Rates Upload
MCE successfully uploaded all of its 70 active Light Green service rates by the CEC’s target date of August 1, 2023, and uploaded its Deep Green service rates by the target date of October 1, 2023, to include time-dependent rates with additional modifiers. A complete list of rates uploaded to MIDAS and their associated Rate Identification Numbers (“RIN”) is included in Appendix A.

The period covered by the initial upload spanned between three and six months, due to data limitations of the MIDAS system. As such, MCE has made subsequent uploads to keep rates current in MIDAS:

1. In October 2023, MCE uploaded additional intervals to ensure all rates were up-to-date through December 31, 2023.
9 2. In November 2023, MCE uploaded additional intervals for all rates through May 1, 2024.6

3.1.2 Future Rates Upload
To the extent that uploading future rates is feasible and cost effective, MCE plans to maintain its generation rates in MIDAS so that customers and their devices may access them for device automation. However, MCE notes that if hourly rates are approved by MCE’s Board, daily uploads of such rates to MIDAS will present significant challenges. Given the current structure of MIDAS and the lack of funding for LSEs to develop systems, processes, and improvements to MIDAS, MCE cannot at this time find that it is cost effective or feasible to maintain current and accurate rates for any future hourly rate offerings in MIDAS.

Nonetheless, MCE is engaged in and monitoring the Demand Flexibility Proceeding at the California Public Utilities Commission (“CPUC”) and is committed to working with the CEC, CPUC, and other stakeholders to help customers automate behavioral changes in electric usage and looks forward to further discussion on how MIDAS may be updated and/or will interact with future rate platforms or repositories yet to be developed such as a CPUC approved Price Machine.

MCE recommends that any future rate repositories be equipped to provide composite rates if the goal is to provide customers with a composite or total real-time rate signal. As a CCA, MCE’s Board has sole authority over its customers’ generation rate component but has no authority to determine the distribution or transmission rate components of its customers’ rates. Any distribution and transmission rate components charged to MCE customers are charged by Pacific Gas & Electric Company (“PG&E”). As such, MCE only plans to upload generation rate components to MIDAS and cannot take responsibility for, be required to calculate, or be required to upload marginal cost rates for rate components and myriad PG&E programs that it has no control over.

3.2 Plan to Provide Rate Identification Number(s) on Customer Billing Statements and Online Account Using Both Text and QR Code
Adopted LMS Amendments Section 1623(c)(4) requests each Large CCA to provide customers with access to their RIN on customer billing statements and online accounts using both text and quick response (“QR”) or similar machine-readable digital code by April 1, 2024.

MCE customers receive their consolidated billing statements from PG&E. MCE provides itemized charges to PG&E through Electronic Data Interchange (“EDI”) transactions. Therefore, MCE is reliant on PG&E to develop its EDI system to accept MCE RINs and display them on customer bills.
6 As of this writing, six of MCE’s Light Green rates are not current in the MIDAS system. These rates serve a small number of large Commercial & Industrial and EV customers with legacy 12p-6p peak periods. Upload attempts are rejected with the message, “An error has occurred.” MCE reached first reached out to CEC staff on November 30, 2023, and has had numerous, ongoing communications with CEC staff on this matter. The issue appears to reside with MIDAS, and not with MCE. CEC Staff has indicated they are aware of the issue, that it is not isolated to MCE and the CEC is working to resolve the issue. MCE will continue to engage and collaborate with the CEC in good faith to fix this issue.
10 CCAs have been working with PG&E to utilize PG&E’s billing transactions to include a CCA specific RIN on customers’ bills. MCE will supply MCE’s RIN mapping table to PG&E who will then include it within the code and display customers’ RINs on the generation portion of their bills. This interpretation has also been corroborated by PG&E in recent CPUC Advice Letters seeking approval to modify customers’ bill presentations to include RINs and QR codes.

On January 16, 2024, PG&E filed Advice Letter 7136-E at the CPUC outlining the process it is undertaking to provide RINs on customer bills. As outlined by PG&E in its second supplemental Advice Letter 7136-E-B filed on March 1, 2024, customers on time-dependent rates will have their bills updated to include a QR code and the customer's RIN in the top right-hand corner of their bill, which can then be scanned to program a customer's device(s). PG&E notes that RINs will be presented the same way on both bundled and unbundled (CCA and Direct Access) customers’ bills.

3.3 Plans and Current Participation in the Development of Single Statewide RIN Access Tool – Amended July 2025
Adopted LMS Amendments Section 1623(c)(1)-(3) requests all LSEs named in the Standards to work together to develop a plan for a single statewide standard tool for authorized rate data access by third parties, along with a single set of terms and conditions for third parties using the tool by October 1, 2024. The tool is to provide the customers’ RINs, provide eligible RINs, enable switching to an available rate by an authorized third party, incorporate applicable cybersecurity measures, minimize enrollment barriers, and be accessible in digital, machine-readable format.

MCE is monitoring and engaging in the process with the other regulated LSEs to develop a Single Statewide RIN Access Tool pursuant to Adopted LMS Amendments Section 1623(c). A proposed plan for the tool was submitted to the CEC for review on October 1, 2024. MCE will continue to collaborate with other parties and the CEC towards the implementation and maintenance of the tool in a timely manner subject to the tool’s approval by the CEC. MCE is unable to specifically identify the full scope and budget of integration of work; commit resources; or review, identify, and plan internal infrastructure needs until the Single Statewide Standard RIN Access Tool’s scope has been designed and approved by the CEC. 4 MCE Rates and Dynamic Rate Considerations
Adopted LMS Amendments Section 1623.1(a)(1) requests each large CCA to develop a plan that evaluates the cost-effectiveness, equity, technological feasibility, benefits to the grid, and benefits to customers of dynamic rates for each customer class. After evaluating dynamic rates, the CCA may instead propose and evaluate specified programs and/or delay or modify its implementation of the LMS.

Adopted LMS Amendments Section 1623.1(b)(2) requests MCE apply to its rate-approving body for approval of at least one dynamic rate by July 1, 2025. The LMS state MCE is to apply for approval only of a dynamic rate only for those customer classes for which the Board determines such a rate will materially reduce peak load.
11 Adopted LMS Amendments Section 1623.1(b)(4) requests each CCA to offer to each of its electricity customers voluntary participation in either a dynamic rate developed according to Section 1623.1(b)(2), if such rate is approved by the Board, or a cost-effective load flexibility program that allows automated response to MIDAS signals for each customer class the Board determines such a program would materially reduce peak load July 1, 2027.

This section provides an overview of MCE’s current time-dependent rates and its plan to evaluate and develop dynamic rates as stated in the LMS.

4.1 Overview of MCE’s Current Time-Dependent Rate Offerings MCE currently offers several options for time-dependent or Time-Of-Use (“TOU”) pricing, consistent with the options available to the broader PG&E service area. Approximately 66 percent of MCE households are on time-dependent rates. Current residential rate options are displayed in the table below.

Table 2: Current MCE Residential Rate Offerings7
MCE Residential Rate Description of Rate Periods
E-1 Flat Rate Pricing, not time
dependent
E-TOU-C - Default Time-of-Use Utilizes 4pm-9pm peak rates every day
E-TOU-D - Time-of-Use Utilizes 5pm-9pm peak rates on
non-holiday weekdays only
ELEC - Time-of-Use for Qualified
Electric Technologies
Utilizes lower rates from
12am-3pm
EV2 - Time-of-Use for Electric
Vehicles
Utilizes lower rates from
12am-3pm
Additionally, MCE continues to provide limited service to legacy residential rate schedules that are no longer available to new customers:
● E-TOU-B - Time-of-Use: Utilizes 4pm-9pm peak rates on non-holiday weekdays only; and ● EV - Time-of-Use for Solar Customers with Electric Vehicles: Utilizes lower rates from 11pm-2pm.

MCE also offers a wide range of options for time-dependent pricing for non-residential customers as depicted in Table 3 below. Except in rare circumstances like street lighting, non-residential service is entirely billed according to time-dependent pricing. All of MCE’s 7 A complete list of MCE Residential rates can be found at https://www.mcecleanenergy.org/rates/. 12 non-residential rates have 4pm-9pm daily peak and seasonal rates, except where noted otherwise.

Table 3: Current MCE Non-Residential Rate Offerings8
MCE Non-Residential Rates Description of Rate Periods
B-1 - Small General Service Utilizes six TOU periods (three in the Summer and three in the Winter)
B-1ST - Small General Service
Plus Storage
Utilizes seven TOU periods (three in the
Summer and four in the Winter)
B-6 - Small General Service
Utilizes five TOU periods (two in the
Summer and three in the Winter) and
stronger pricing signals relative to rate
schedule B-1
B-10 - Medium General
Service
Utilizes six TOU periods (three in the
Summer and three in the Winter) and
three voltage levels with discrete rates
B-19 - Medium General
Service
Utilizes six TOU periods (three in the
Summer and three in the Winter), TOU
and seasonal based demand charges, and
three voltage levels with discrete rates
B-19 Option R - Medium
General Service for Solar
Utilizes six TOU periods (three in the
Summer and three in the Winter), no
demand charges, and three voltage levels
with discrete rates
B-20 Option R - Large General
Service for Solar
Utilizes six TOU periods (three in the
Summer and three in the Winter), no
demand charges, and three voltage levels
with discrete rates
BEV - Commercial EV
Charging
Utilizes three TOU periods, no
seasonality, and three voltage levels with
discrete rates
AG-A - Small Agriculture
Utilizes four TOU periods (two in the
Summer and two in the Winter), and uses
a 5pm-8pm peak pricing period
8 A complete list of MCE Non-Residential rates can be found at https://www.mcecleanenergy.org/commercial-rates/. 13 MCE Non-Residential Rates Description of Rate Periods AG-B - Medium Agriculture
Utilizes four TOU periods (two in the
Summer and two in the Winter), 5pm-8pm peak pricing period AG-C - Large Agriculture
Utilizes four TOU periods (two in the
Summer and two in the Winter), 5p-8p
peak, summer peak demand
AG-F - Flexible TOU
Agriculture
Utilizes AG-A/AG-B/AG-C variations as
above, with two designated 24-hour off-peak days
SB - Standby Service
Utilizes six TOU periods (three in the
Summer and three in the Winter), a
reservation charge per kW, and three
voltage levels with discrete rates
SL-1 - Street, Highway, and
Outdoor Lighting This rate is not time dependent
TC-1 - Traffic Control Service This rate is not time dependent MCE also continues to offer limited service to legacy non-residential rate schedules without a 4pm-9pm peak. Eligibility is determined by PG&E according to tariffs approved by the CPUC.

These rates have a 12pm-6pm peak and seasonal rates, except where otherwise noted, and have weak pricing signals and are of limited significance to MCE’s portfolio. Only 6.5 percent of MCE customers – almost entirely small commercial accounts – are served by these rates.

Table 4: MCE Legacy Rates
MCE Legacy Rates Description of Rate Periods
A-1 - Small General Service This is a non-TOU rate
A-1X - Small General Service Utilizes five TOU periods (three in the Summer and two in the Winter)
A-6 - Small General Service Utilizes five TOU periods (three in the Summer and two in the Winter)
A-10 - Medium General Service This is a non-TOU rate but includes three voltage levels with discrete rates
14 MCE Legacy Rates Description of Rate Periods
A-10X - Medium General Service
Utilizes five TOU periods (three in the
Summer and two in the Winter) and
three voltage levels with discrete rates
E-19 - Medium General Service
Utilizes five TOU periods (three in the
Summer and two in the Winter), demand
charges, and three voltage levels with
discrete rates
E-20 - Large General Service
Utilizes five TOU periods (three in the
Summer and two in the Winter), and
three voltage levels with discrete rates
E-20 Option R - Large General
Service for Solar Customers
Utilizes five TOU periods (three in the
Summer and two in the Winter), and
three voltage levels with discrete rates
AG-1 - Small Agricultural Service This is a non-TOU rate AG-4-A - Time-of-Use Agricultural
Service
Time-of-Use Agricultural Service:

Includes four TOU periods (two in the
Summer and two in the Winter) and a
connected load charge
AG-4-B - Time-of-Use Agricultural
Service
Utilizes four TOU periods (two in the
Summer and two in the Winter) and a
maximum demand charge
AG-4-C - Time-of-Use Agricultural
Service
Utilizes five TOU periods (three in the
Summer and two in the Winter) and a
peak demand charge
AG-5-A - Time-of-Use Agricultural
Service
Utilizes four TOU periods (two in the
Summer and two in the Winter) and a
connected load charge
AG-5-B - Time-of-Use Agricultural
Service
Utilizes four TOU periods (two in the
Summer and two in the Winter) and a
maximum demand charge
AG-5-C - Time-of-Use Agricultural
Service
Utilizes five TOU periods (three in the
Summer and two in the Winter) and a
peak demand charge
AG-R - Time-of-Use Agricultural
Service with Off Peak Days
Utilizes four TOU periods (two in the
Summer and two in the Winter), two day-
15 MCE Legacy Rates Description of Rate Periods
of-week options, two service levels, and
connected load or demand charges
AG-R - Time-of-Use Agricultural
Service with Variable Peak
Utilizes four TOU periods (three in the
Summer and two in the Winter), three
peak hour options, two service levels,
and connected load or demand charges
S - Standby Service
Utilizes five TOU periods (three in the
Summer and two in the Winter),
reservation charge per kW, and three
voltage levels with discrete rates
MCE also offers two energy supply programs that are charged or credited to the customer’s energy bill but separate from each customer’s electric rate schedule:
● Deep Green Service: This program allows customers to choose 100 percent renewable energy content and includes a $0.01/kWh flat adder to all rates. ● Disadvantaged Communities Green Tariff (“DAC-GT”): This program allows eligible customers in disadvantaged communities to choose 100 percent renewable energy content and receive a 20 percent total bill discount.

4.2 Dynamic Rates Evaluation – Amended July 2025
MCE strongly appreciates and supports the LMS’ goals to help encourage customers to shift energy consumption away from peak periods to minimize costs, improve reliability, and better align renewable energy supply and demand. MCE also agrees that two tools that can be utilized to encourage such a shift are flexible rate designs and automation technology.

Consistent with the adopted LMS, in this section MCE outlines its plan to evaluate future dynamic marginal cost-based rate offerings for its customers and provides an initial evaluation of the cost-effectiveness, equity, technological feasibility, and benefits of dynamic rates.

As a CCA, MCE’s Board has sole authority over its customers’ generation rate component and no other entity, including the CEC or CPUC, has the authority to set generation rates for MCE customers. Similarly, this means that MCE does not have authority to determine the distribution or transmission rate components of its customers. Any distribution and transmission rate components charged to MCE customers are determined and charged by PG&E, as approved by the CPUC and/or Federal Energy Regulatory Commission. As such, any dynamic or hourly rates adopted by MCE’s Board will be generation-only. MCE and its Board cannot take responsibility for, or be required to calculate, rates for components that it has no control over such as distribution and transmission rate components.
16 MCE understands that there may be value in dynamic rates or dynamic rate pilots, and is currently offering all the dynamic rate pilots approved by the CPUC for PG&E’s service area9 as well as offering its own, distinct dynamic EV rate pilot to its customers, MCE Sync Dynamic Rewards. 10 These pilots should allow MCE to collect data to evaluate the cost-effectiveness, equity, feasibility, and customer and grid benefits of such rates to inform MCE’s future rate designs and offerings. Generally, MCE notes that it has a preference to create and offer MCE specific rates, pilots, and programs that can be uniquely tailored and administered by MCE to meet the needs of its customers, which may be distinct from other regions of PG&E’s service area and rely on MCE’s significantly clean and GHG-free portfolio in the California Independent System Operator markets.

In evaluating whether to offer future additional dynamic rates and/or pilots, MCE plans to evaluate portfolio-based cost-effectiveness, technical feasibility, equity, and benefits to MCE and its customers and the environment. MCE will consider what pricing options, if any, offer cost-effective and material, incremental, benefits over current rate and load flexibility offerings.

Offering dynamic rate pilots should provide necessary and useful data to evaluate and determine the appropriateness (and potential design) of future dynamic rate offerings in MCE’s service area.

In the version of this plan approved by the Board on May 16, 2024, MCE found that it did not have sufficient evidence to conclude that developing and implementing dynamic rates in MCE’s service area on the timeline outlined in the LMS would be cost effective or provide material incremental reductions to peak load beyond those of its current rate and programs portfolio for any customer class. The Board-approved plan found it necessary to modify Section 1623.1(b)(2)’s request for MCE to apply for approval of a dynamic rate by July 1, 2025. The Board-approved plan concluded that the timeline must be modified to ensure cost-effective implementation and that MCE Staff may, but was not required to, propose such a rate to the Board by the target date of July 1, 2025. At that time, MCE could not commit to creating such a rate for Board approval by July 1, 2025. However, MCE is interested in collecting the data necessary to make such determinations and is now offering dynamic rate pilots in its service territory. MCE began offering the MCE Sync Dynamic Rewards pilot in September 2024, and on April 4, 2025, MCE’s Board approved MCE’s participation in the dynamic rate pilots offered in PG&E’s service area:

Expanded Pilot 1, Expanded Pilot 2, and the VGI-Commercial Pilot, and therefore has met the original timeline adopted in Section 1623.1(b)(2). MCE will provide updates to its Board in its next plan iteration and any annual reports.
9 California Public Utilities Commission Decision (D) 24-01-032 approved the expansion of two demand flexibility pilots in PG&E's service area that allow CCA participation. Under the Transportation Electrification Rulemaking 18-12-006, the CPUC further authorized PG&E’s vehicle-to-grid (VGI) pilots with a dynamic rate that allow CCA participation. MCE is currently offering all three pilots to its customers. 10 The MCE Sync Dynamic Rewards pilot allows customers the chance to receive additional savings in MCE Sync by responding to dynamic hourly price signals (based on day-ahead CAISO prices for the PG&E Default Load Aggregation Point (DLAP). Customers who enroll in the dynamic pilot will receive an enrollment bonus of $50 and then receive a monthly reward payment for allowing MCE Sync to charge their car according to the dynamic price signal.
17 a. Cost-Effectiveness
In determining whether to offer dynamic rates that vary at least hourly as outlined in the LMS, one evaluation factor that MCE will consider is cost-effectiveness.

MCE notes that the CEC’s adopted LMS state there shall be no reimbursement to local government agencies for the costs of carrying out the Standards as the Commission has found them to be cost effective, noting that savings realized will outweigh the costs associated with implementing the programs.11 While MCE appreciates the plain language of the LMS, MCE disagrees that the cost-effectiveness of any rates or programs could be determined before those rates or programs actually exist. At this point there exists no evidence to conclude that MCE will realize any net savings from implementing the LMS. It is too early in MCE’s offering of hourly or dynamic rates or pilot programs to allow for sufficient analysis of the effectiveness (cost or otherwise) of dynamic rates in its service area. MCE has so far incurred only costs associated with the LMS and any benefits remain to be realized.

Nonetheless, MCE shares many of the CEC’s stated goals in developing the LMS and is committed to encouraging customers to shift energy consumption to off-peak periods. MCE appreciates and understands that there may be significant value in dynamic rates and is interested in collecting the necessary information and data to determine if, and under what conditions, dynamic rates would be cost effective for MCE and its customers.

As of September 2024, MCE implemented an hourly rate pilot for its electric vehicle (“EV”) customers, MCE Sync Dynamic Rewards.
12 MCE is also participating in, monitoring, and
evaluating the status of CPUC approved PG&E dynamic rate pilots. However, without such primary data, MCE cannot at this time determine that such a rate or program will provide material incremental reductions to peak load or be cost effective for any customer class.

Significant uncertainties remain in both the cost to develop and the value MCE can reliably realize from implementing hourly rates. MCE anticipates that developing dynamic rates may result in significant costs and MCE’s ability to realize the value of such rates will be determined by unknown factors like customer adoption and incremental response levels. Without robust pilot results in MCE’s and PG&E’s service area to perform a comprehensive analysis, MCE cannot accurately estimate development costs, the estimated total benefits, or whether those benefits would be likely to offset the costs for any customer class. Accordingly, MCE recommends the Board not require MCE to propose dynamic rate to its Board by the target date of July 1, 2025.

MCE recommends the Board find that MCE may, but is not required to, propose such a rate by the target date.

MCE will continue to evaluate whether to offer future dynamic rate pilots and rates to its customers and will evaluate the results of its own pilot and the pilots in PG&E’s service area.

MCE will use the pilots as an opportunity to collect the data necessary to conduct its own cost-11 CEC Load Management Standards Section 1623.1(e). 12 See footnote 10. 18 effectiveness analysis with MCE specific data, which would be used to inform future rate and program offerings as well as future iterations of MCE’s LMS Plan.

In conducting such a future cost-effectiveness analysis, MCE expects to compare the benefits of the rate offering with costs of implementation. Estimated costs include but are not limited to rate development, rate and program administration, and technology costs. Estimated benefits include, but are not limited to, lower energy costs, increased load reduction, avoided energy and capacity costs, and reliability benefits. To demonstrate cost-effectiveness, the expected benefits for each rate must exceed the costs of implementation. MCE looks forward to providing updates to its Board, the CEC, and other interested parties as it moves forward. b. Equity
Similarly to cost-effectiveness, MCE currently has no primary data sources to quantitatively speak to the equity component of offering hourly rates to its customers. MCE is committed to increasing equitable and affordable access to clean energy for its customers. While reductions in peak demand provide grid benefits to all customers and those benefits could theoretically lower power procurement costs to all customers, currently there is not clear evidence that all MCE customers will benefit from lower rates. As MCE begins to evaluate whether to offer hourly rates to all customers, several equity components will be considered including:

Equitable Access to Automation and Benefits
Customers’ ability to benefit from highly differentiated rates is directly linked to their ability to respond to those rates. Customers that can automate portions of their load will be best equipped to respond to pricing signals and benefit through lower energy bills or performance-based payments. Therefore, equitable access to automation devices and technology will be critical in ensuring that all customers can benefit from these rates. As such, MCE Staff believes it is appropriate to explore ways to ensure that customers on dynamic rates can access automation technology in an equitable manner. MCE may therefore explore offering additional incentives to provide automation technology for low-income customers and/or those who live in disadvantaged communities or multi-family properties who may otherwise not be able to benefit from automated load shifting programs or dynamic rates.

Cost Shifting
Assuming any change in rate design is designed to collect the same total level of revenue from all customers (i.e. revenue requirement), any change to rate design or structure means that some customers will pay less and some customers will pay more – without any changes to their behavior.13 This mathematical reality is often referred to as a cost shift, as costs are shifted from one group of ratepayers to another. When rate offerings are voluntary, or opt-in, there is a greater risk that customers will simply choose the rate which allows them to pay less without making any changes to their behavior. These customers who can elect to participate in a rate that will lower their costs (and shift costs to other customers within their class) without any changes in behavior can be referred to as structural benefactors. 13 This is at least true in the short-term. However, in the long-term material reductions/changes in behavior may lower the total revenue requirement and those cost savings could be passed through to all customers. 19 In developing dynamic rates with the goal of encouraging customers to change their behavior and shift their energy consumption away from peak hours, one of MCE’s goals will be to minimize the amount of cost shifting that occurs between customers, particularly due to structural benefactors. To do so, MCE will aim to ensure that customers on hourly rates are sufficiently able to respond to price signals, whether through automation and/or price signals that are strong enough to incent behavioral change.

Customer Location
With few exceptions, customers do not choose where they are located on the electrical grid. It is partly because of this fact that grid infrastructure and energy costs have historically been spread, or averaged, across all customers. For example, rural customers have not been charged different prices for energy than city dwelling customers and MCE customers in Concord have not paid more than MCE customers in San Rafael, despite the potential differences in costs to serve those customers at any point in time (for example, due to local grid constraints). With a move to dynamic rates and advances in technology, it may be possible to charge customers in the same rate class and on the same tariff at different rates at any point in time given their location on the grid.

In both the CEC’s LMS Rulemaking and the CPUC’s Demand Flexibility Proceeding, there has been discussion on the level of locational granularity that should be applied to hourly or sub-hourly rates. While MCE and others are likely to first utilize hourly rates that do not vary at a level more granular than the Default Load Aggregation Point, there has been discussion of rates that vary at more granular levels, such the circuit or transformer level. Essentially, this means that the level of local grid constraint can affect the rates a customer in that area pays for electricity. MCE believes this is an important equity concern that cannot be overlooked.

Local grid constraints vary based on grid infrastructure, design, and capacity constraints that are generally outside of any individual customer’s control. The more locational granularity in rates, the more potential there is for equity issues to arise. To address this issue, evaluation should be done to ensure that dynamic pricing based on localized grid constraints does not particularly burden low-income residents or those in disadvantaged communities. MCE does not currently have data on how more granular locational variation in rates may impact equity but urges all California LSEs as well as the CEC and CPUC to work to ensure that certain customers are not unfairly harmed by future rate design simply due to their location on the grid. c. Technological Feasibility
MCE expects that it is technically feasible to offer a dynamic hourly generation rate option by July 1, 2027, as outlined in the LMS, contingent upon PG&E providing revenue quality billing data to MCE on an hourly level or developing a reliable workaround. Current PG&E billing transactions do not include the hourly interval data which would be matched against hourly dynamic prices. MCE hopes that as PG&E develops CPUC approved hourly pricing pilots, this data will become available.

MCE notes that even if dynamic rates are technically feasible, daily rate uploads to MIDAS will need to be supported by the development of new systems, which may delay or otherwise impede offering dynamic rates in the near term. The limitations of the current MIDAS system and 20 the lack of funding for LSEs to develop systems for interacting with MIDAS may mean that it will not be cost effective or feasible to maintain dynamic rates in MIDAS at this time. d. Benefits to the Grid and Customers
MCE will also consider benefits to the grid and benefits to customers in its evaluation of dynamic rates. Assuming material changes in energy consumption behavior by customers, potential grid benefits resulting from hourly rates include but are not limited to reliability benefits, deferred, and reduced grid infrastructure investments, and environmental benefits.

Potential direct customer benefits include, but are not limited to, lower energy expenditures, reliability benefits, and theoretically lower rates – assuming material reductions to peak load that result in lower overall energy costs and reduced capacity and compliance costs. MCE does not currently have the data to quantify benefits to the grid and customers resulting from offering hourly rates in its service territory. MCE plans to continue to gather data on this topic and will update this section in future iterations of its plan and annual reports.

4.3 Dynamic Rate Development and Application Plan – Amended July 2025 Adopted LMS Amendments Section 1623.1(b)(2) of the LMS requests MCE and other Large CCAs apply to its rate-approving body for approval of at least one dynamic rate by July 1, 2025.

The LMS state MCE should apply for approval of a dynamic rate only for those customer classes for which the Board determines such a rate will materially reduce peak load. This section outlines how MCE plans to work toward this goal.

MCE has been, and plans to remain, actively engaged in dynamic rates discussions and proceedings at the CPUC and CEC. To date, MCE has committed considerable staff time, which amounts to significant and material cost to MCE, to these efforts, including making staff available to attend all noticed CEC LMS working group meetings and engaging in the CPUC’s Demand Flexibility proceeding. Additionally, MCE is conducting research internally and in collaboration with external partners on how it might best design and offer dynamic rates in the future.

As of September 2024, MCE began offering a dynamic rate pilot, MCE Sync Dynamic Rewards, for its electric vehicle (“EV”) customers. MCE is also participating in, monitoring, and evaluating the status of CPUC approved PG&E dynamic rate pilots. However, without such primary data, MCE cannot at this time determine that such a rate or program will provide material incremental reductions to peak load or be cost effective for any customer class.

Without robust pilot results in MCE’s and PG&E’s service area to perform a comprehensive analysis, MCE cannot accurately estimate development costs, the estimated total benefits, or whether those benefits would be likely to offset the costs. Accordingly, MCE recommends the Board not require MCE to propose a dynamic, hourly marginal cost-based rate, to its Board by the target date of July 1, 2025. MCE recommends the Board modify the request in LMS Section 1623.1(b)(2) that MCE propose dynamic rates by July 1, 2025, and declare that MCE may, but is not required to, propose such a rate to the Board for approval by July 1, 2025.

MCE will continue to evaluate if and how it may offer dynamic rates to its customers and will provide updates to its Board in its next plan iteration and any annual reports, and looks forward to continuing conversation and collaboration with stakeholders on possible pilot design, including how best to collect data that will effectively illustrate the costs and benefits of different dynamic rate structures and incorporate rates into MIDAS.

Additionally, LMS Section 1623.1(b)(4) requests MCE offer customers voluntary participation in either a dynamic rate, if approved by the Board, or a cost-effective load flexibility program by July 1, 2027. MCE notes that its offerings as of July 1, 2027, cannot be known at present, and the future timeline for deployment of future rate and program offerings will be dependent on future Board guidance and approval.

MCE plans to continue to provide updates to its Board as well as the CEC, as outlined in the LMS, and will further address the details of rate design and infrastructure needs as they become available.
5 Load Flexibility Programs
Adopted LMS Amendments Section 1623.1(b)(3) of the LMS requests MCE submit a list of cost-effective load flexibility programs to the CEC Executive Director by October 1, 2024. The portfolio of load flexibility programs is to provide at least one option to automate response to MIDAS signals for every customer class where such a program is determined by the Board to materially reduce peak load. If MCE’s Board does not approve of and offer dynamic rates by July 1, 2027, the Standards state that MCE can meet the goals of the LMS by offering voluntary participation in a cost-effective MIDAS-integrated load flexibility program.

5.1 Overview of MCE Load Flexibility Programs
Residential Programs
MCE Sync
MCE Sync is an MCE-funded Automated Load Management program that utilizes a smart charging app to reduce EV owner’s charging load during peak times, while also seeking to align 22 EV charging load with high-solar daytime hours.14 MCE began offering MCE Sync to eligible customers in 2021 and the program offers customers a flat monthly credit for participating in events.

Through 2023, MCE Sync had approximately 2,200 enrolled MCE customers who charge their EVs at home via a software platform which delivers direct load control of EV charging using vehicle telematics and networked electric vehicle supply equipment. To date, the program has shifted 90 percent of EV charging events out of the 4 pm – 9 pm window. An analysis of program data through May 2022 showed that customers saved an average of $10 shifting charging to off-peak hours.

MCE Sync does not currently have rates associated with events. MCE Staff are currently exploring the possibility of expanding the program in MCE’s service area, including integrating dynamic pricing elements into future program offerings.

Peak FLEXmarket
MCE’s Peak FLEXmarket program is a market-driven demand flexibility program that assigns an hourly value to measured, behind-the-meter (“BTM”) impacts.15 Peak FLEXmarket is aimed at shifting load away from peak periods and provides customers with direct payments for measured load shedding or shifting during events, based on deviations from their individual baseline.

Peak FLEXmarket has successfully engaged new aggregators who have not participated in demand response, as well as program partners who have traditionally been confined to energy efficiency project development by presenting a value proposition for load flexibility. This program is a framework with the tools to measure and value hourly reductions in energy use and is technology agnostic.

MCE’s Richmond VPP Pilot is expected to provide significant bill savings for customers and significant local and grid benefits. MCE currently expects the pilot to launch in 2025.

Residential Efficiency Market
MCE’s Residential Efficiency Market program is focused on incentivizing customers to install measures that can help reduce peak load.17 Customers can receive a 20 percent upfront cash 14 See https://www.mcecleanenergy.org/mce-sync/. 15 See https://www.mcecleanenergy.org/peak-flexmarket/. 16 See http://mcecleanenergy.org/vpp. 17 See https://www.mcecleanenergy.org/flexmarket/. 23 payment for the forecasted value of their energy efficiency projects and additional payments for metered savings of those energy efficiency projects.

Solar Storage Credit
MCE’s Solar Storge Credit program is aimed at encouraging customers to discharge their energy storage systems from 4-9pm daily.18 To be eligible for the credit, customers must be enrolled in a time-of-use rate, automate their battery to discharge from 4-9 p.m. daily and set their battery reserve to no more than 20 percent, except when preparing for or during a power outage.

Customers are eligible to receive up to $20/month for participation based on their solar system’s size.

Nonresidential Programs
Peak FLEXmarket
MCE’s Peak FLEXmarket program is a market-driven demand flexibility program that assigns an hourly value to measured BTM impacts. Peak FLEXmarket is aimed at shifting load away from peak periods and provides customers with direct payments for measured load shedding or shifting during events, based on deviations from their individual baseline.

5.2 Evaluation of Programs
This section evaluates the cost-effectiveness, equity, technological feasibility, and benefits to the grid and customers of implementing programs that enable automated response to MIDAS signals. As discussed below, MCE cannot currently conclude that creating a new, or modifying an existing, load-modifying program to allow automated responses to MIDAS signals would be cost effective or offer material incremental benefit, such as material incremental peak load reduction, for any customer class.

Accordingly, MCE will continue to offer voluntary participation in its existing and future load flexibility programs. MCE will continue to consider the cost-effectiveness and peak load reduction potential of programs that enable automated response to MIDAS signals. To the extent that MCE’s Board does not approve a dynamic rate offering by 2027, and MCE is at that 18 See https://www.mcecleanenergy.org/solar-storage-credit/. 19 See https://www.mcecleanenergy.org/flexmarket/. 24 time able to determine that modifying an existing program or creating a new program that enables automated response to MIDAS signals is cost effective and provides material incremental reductions to peak load for at least one customer class, MCE may at that time integrate a load-modifying program into MIDAS.

MCE will therefore submit to the CEC a list of load-modifying programs deemed cost-effective by October 1, 2024, but recommends the Board find that MCE is not required to include a program that allows automated response to MIDAS signals as it cannot determine such a program would be cost effective or produce material reductions to peak load for any customer class.

5.2.1 Cost Effectiveness
As outlined by section 1623.1(b)(3) of the LMS, MCE will provide a list of load-modifying programs deemed cost effective to the CEC by October 1, 2024. At present, MCE expects that the list of cost-effective programs will include the following MCE load-modifying programs:

1. Peak FLEXmarket;

2. Commercial Efficiency Market; and

3. Residential Efficiency Market.

These programs are funded by ratepayers through MCE’s Energy Efficiency Portfolio as authorized by the CPUC. To receive ratepayer funding, the CPUC requires MCE to demonstrate its energy efficiency portfolio is cost effective using CPUC-approved cost-effectiveness criteria.

MCE does not currently expect to utilize program offerings with automated responses to MIDAS signals; however, if MCE’s Board does not adopt an hourly rate by July 1, 2027, MCE may then evaluate whether there is an opportunity to create a new program or modify an existing program to allow responses to MIDAS signals. In doing so, MCE would look at the incremental value of each option, and if modifying an existing, or creating a new, program is deemed cost-effective and found to provide material reductions to peak load may elect to do so at that time.

MCE cannot currently conclude that the modification of current or development of new programs that allow for automated responses to dynamic price signals would be cost effective for any customer class. Developing new programs or modifying existing programs would require MCE to incur costs associated with design and implementation, along with new technology costs. 25 While these costs could potentially be offset with capacity or energy cost savings, the magnitude of those benefits is uncertain.

In conducting future cost-effectiveness analyses, MCE would compare expected program benefits to expected costs of program design and implementation. Assuming incremental load shift that can be attributed to the program, expected benefits of a new load flexibility program that allows for automated response to MIDAS signals may include, but are not limited to, avoided energy and capacity costs, improved reliability, and environmental benefits. Expected costs may include, but are not limited to, program development costs, program administration costs, and technology and implementation costs.

5.2.2 Equity
MCE is committed to creating more equitable communities and providing equitable access to clean energy benefits throughout its service area. In choosing to modify or offer any program, MCE carefully considers equity impacts and has demonstrated its commitment to equitable program offerings since its inception. MCE aims to offer a suite of programs that provide customers with access to clean energy technology and services while lowering bills and greenhouse gas emissions. Some examples of MCE’s commitment to equity include MCE’s:

1. Income-qualified customer programs such as the Low-Income Families and Tenants Program, the MCE Cares Credit Program, DAC-GT program, and EV Rebate Program;

2. Commercial Equity Program;

3. Commitment to advancing supplier diversity and workforce development; and

4. MCE’s Community Power Coalition.20
In evaluating any future load-modifying program offerings, MCE will plan to evaluate how that offering may impact customer equity. Potential evaluation criteria include, but are not limited to, equitable access to technology, direct customer benefits and bill impacts, and cost-shifting between and within rate classes. For example, most customers’ ability to benefit from highly differentiated rates will be directly linked to their ability to respond to those rates. Customers that can automate portions of their load will be best equipped to respond and benefit. Therefore, equitable access to automation devices and technology will be critical in ensuring that all customers can benefit from load-modifying programs. To promote equitable access to automation technology MCE may explore providing additional incentives for low-income customers and/or those who located in disadvantaged communities or multi-family properties who may otherwise not be able to benefit from automated load shifting programs or dynamic rates.

5.2.3 Technological Feasibility
MCE is committed to offering load-modifying programs that encourage customers to shift their load away from periods of grid constraint and high greenhouse gas emissions. MCE strongly supports the LMS’ goals to provide customers and their devices access to signals that may help 20 More information on MCE’s energy equity efforts can be found on its website at https://www.mcecleanenergy.org/energy-equity/#energyequity. 26 automate their response to marginal signals such as prices and greenhouse gas signals to provide the greatest level of benefit for both the customer and the grid. MCE has demonstrated this support through the development of its MCE Sync EV charging mobile application and the MCE Peak FLEXmarket platform, both of which are technology platforms that help customers adjust their energy consumption through greater visibility. And while MCE believes it is technically feasible to offer customers programs that allow customers to respond to MIDAS signals, currently, both of these load-modifying programs are incompatible with the MIDAS database, and MCE cannot conclude that modifying them to be compatible would be cost effective or result in material incremental load reduction:
21 ● MCE Sync - This program provides a flat monthly credit to customers for participating in events, and does not have rates associated with events, and thus would not support inclusion in MIDAS.
● PeakFLEX Market - There is currently no way for MIDAS to show customers their current real-time rate for this program, as it is based on separate prices (baseline and above-baseline) that depend on a customers’ individual usage history, which is not a component of MIDAS.

5.2.4 Benefits to the Grid and Customers
In considering whether to modify existing or offer new load-modifying programs, including those that allow automated response to MIDAS signals, MCE may consider benefits to the grid and customers.

Assuming incremental load shift or reduction that can be attributed to the program, potential grid benefits include reduced capacity costs (for example through lower Resource Adequacy costs), reduced of deferred transmission and distribution system upgrades, lower energy costs, increased reliability benefits, and environmental benefits.

Assuming incremental load shift or reduction that can be attributed to the program, potential customer benefits include pass-through energy cost savings from grid benefits as well as pass-through cost savings from potential reduced compliance costs for MCE, improved reliability, improved environmental benefits, and direct cost savings from participation in load-modifying programs.
21 While not a load-modifying program, MCE also notes that its Disadvantaged Community Green Tariff program is also not included in MIDAS currently as it is not compatible with the current design of MIDAS. The 20 percent bill discount for the DAC-GT program is calculated from a customer’s total billed charges, inclusive of non-volumetric and variable IOU charges, by reading the total charges from the previous bill. As such, MCE cannot generate a volumetric price inclusive of this discount.
27 All of these potential grid and customer benefits depend on the reliability and magnitude of load shift and reduction that load-modifying programs are able to achieve. MCE is at this time unable to conclude that future programs or modifications to existing programs to allow automated responses to MIDAS signals would result in material grid benefits relative to MCE’s existing offerings or result in pass through savings to customers for any customer class. If MCE creates a load-modifying program that allows automated response to MIDAS signals in the future it will aim to design the program in such a way to generate material benefits to the grid and MCE customers.
6 Public Information Program
Adopted LMS Amendments Section 1623.1(b)(5) of the LMS requests MCE and other Large CCAs to conduct a public information program to inform and educate affected customers on why dynamic rates or load flexibility programs and automation are needed, how they will be used, and how these rates and programs can save customers money.

MCE appreciates the LMS’ intent to ensure that any load-modifying rates or programs developed are effectively marketed to customers with the aim of encouraging enrollment and maximizing customer success and grid benefits. As a local, community-based organization, MCE values and is deeply committed to providing quality customer and community communication, education, collaboration, and customer service.

As a general matter, all MCE rates and programs can be found on MCE’s website. Any future dynamic rates or load-modifying programs will also be listed and described on its webpage.22 MCE utilizes best practices to provide consistent and accurate communications and response support with its customers and communities. This includes utilizing various communication mediums including joint rate mailers, emails, direct mail, e-newsletters, press releases, webinars, social media posts, public presentations and event attendance and sponsorship throughout MCE’s member communities. In 2023 alone, MCE attended more than 250 events in our service area and presented to 69 local community organizations and city councils. MCE plans to continue communication best practices to maintain its outreach, education, and marketing of rates, programs, and pilots that support load flexibility and recognize the benefits of reducing peak load and using energy during periods of higher renewables supply. In addition, MCE has developed an in-house service center to support and effectively respond to customer inquiries and further the education and benefits of load-modifying programs.

Historically, MCE has voluntarily utilized various types of marketing campaigns to drive enrollment and successful participation in rate and program offerings including those created for load-modifying purposes. For example, to encourage customers to shift load on Time-of-Use rates, MCE conducted a public information campaign that included direct mail, website updates, digital advertising, streaming, and radio placement encouraging customers to use less energy during the 4pm - 9pm peak period targeted to customers throughout MCE’s service area.23 22 MCE Residential rates can be viewed at https://www.mcecleanenergy.org/rates/. MCE Commercial rates can be viewed at https://www.mcecleanenergy.org/commercial-rates/. MCE program offerings can be found at https://www.mcecleanenergy.org/customer-programs/. 23 See https://www.mcecleanenergy.org/4-9/. 28 MCE notes that the LMS do not include a timeline for the public information campaign. As there is no timeline expressed in the Standards and MCE has not created or recommended Board approval of any new hourly marginal cost-based rates or programs that allow automated response to MIDAS signals, MCE does not have details on what future public information programs may entail. MCE expects that if dynamic rates or new load flexibility programs are adopted MCE would utilize a public information program to drive customer adoption, understanding, and success in said rates or programs.

At a minimum, MCE would expect the public information program to highlight how individual customers may be impacted (i.e. bill impacts) and how changes to their behavior can create grid and/or environmental benefits for all customers. This type of public information program would utilize some or all the following communication mediums: direct mail, email correspondence, website updates, social media posts, webinars, television/streaming commercials, press releases or news articles, and public presentations. MCE may also work with its community partners and/or program and technology partners to develop and deliver any public information programs.

MCE expects that any public information campaign would require incremental costs that are not currently accounted for, and MCE would need to factor these public information and response program costs and their recovery into any cost-effectiveness analysis and recommendation to its Board.
29 7 Appendix
Appendix A – MCE MIDAS Rate Identification Numbers
The below table displays the RINs associated with each of MCE's residential and non-residential rates and rate permutations that have been uploaded to MIDAS.

RIN Rate Schedule Energy Supply
Product
USCA-XXMC-PBZD-0000 ETOUB Deep Green
USCA-XXMC-PCZD-0000 ETOUC Deep Green
USCA-XXMC-PDZD-0000 ETOUD Deep Green
USCA-XXMC-OZZD-0000 ELEC Deep Green
USCA-XXMC-QAZD-0000 EVA Deep Green
USCA-XXMC-QUZD-0000 EV2 Deep Green
USCA-XXMC-AXZD-0000 A1X Deep Green
USCA-XXMC-EZZD-0000 B1 Deep Green
USCA-XXMC-ETZD-0000 B1ST Deep Green
USCA-XXMC-CZZD-0000 A6 Deep Green
USCA-XXMC-IZZD-0000 B6 Deep Green
USCA-XXMC-BXCD-0000 A10SX Deep Green
USCA-XXMC-FZCD-0000 B10S Deep Green
USCA-XXMC-BXBD-0000 A10PX Deep Green
USCA-XXMC-FZBD-0000 B10P Deep Green
USCA-XXMC-BXDD-0000 A10TX Deep Green
USCA-XXMC-FZDD-0000 B10T Deep Green
USCA-XXMC-LZCD-0000 E19S Deep Green
USCA-XXMC-GZCD-0000 B19S Deep Green
USCA-XXMC-LZBD-0000 E19P Deep Green
USCA-XXMC-GZBD-0000 B19P Deep Green
USCA-XXMC-LZDD-0000 E19T Deep Green
USCA-XXMC-GZDD-0000 B19T Deep Green
USCA-XXMC-LRCD-0000 E19SR Deep Green
USCA-XXMC-GRCD-0000 B19SR Deep Green
USCA-XXMC-LRBD-0000 E19PR Deep Green
USCA-XXMC-GRBD-0000 B19PR Deep Green
USCA-XXMC-LRDD-0000 E19TR Deep Green
USCA-XXMC-GRDD-0000 B19TR Deep Green
USCA-XXMC-MZCD-0000 E20S Deep Green
USCA-XXMC-HZCD-0000 B20S Deep Green
USCA-XXMC-MZBD-0000 E20P Deep Green
USCA-XXMC-HZBD-0000 B20P Deep Green
30 RIN Rate Schedule Energy Supply
Product
USCA-XXMC-MZDD-0000 E20T Deep Green
USCA-XXMC-HZDD-0000 B20T Deep Green
USCA-XXMC-MRCD-0000 E20SR Deep Green
USCA-XXMC-HRCD-0000 B20SR Deep Green
USCA-XXMC-MRBD-0000 E20PR Deep Green
USCA-XXMC-HRBD-0000 B20PR Deep Green
USCA-XXMC-MRDD-0000 E20TR Deep Green
USCA-XXMC-HRDD-0000 B20TR Deep Green
USCA-XXMC-DAED-0000 AGA1 Deep Green
USCA-XXMC-DAFD-0000 AGA2 Deep Green
USCA-XXMC-DBZD-0000 AGB Deep Green
USCA-XXMC-DCZD-0000 AGC Deep Green
USCA-XXMC-DGED-0000 AGFA1 Deep Green
USCA-XXMC-DGFD-0000 AGFA2 Deep Green
USCA-XXMC-DGGD-0000 AGFA3 Deep Green
USCA-XXMC-DHED-0000 AGFB1 Deep Green
USCA-XXMC-DHFD-0000 AGFB2 Deep Green
USCA-XXMC-DHGD-0000 AGFB3 Deep Green
USCA-XXMC-DIED-0000 AGFC1 Deep Green
USCA-XXMC-DIFD-0000 AGFC2 Deep Green
USCA-XXMC-DIGD-0000 AGFC3 Deep Green
USCA-XXMC-DJZD-0000 AG4A Deep Green
USCA-XXMC-DKZD-0000 AG4B Deep Green
USCA-XXMC-DLZD-0000 AG4C Deep Green
USCA-XXMC-DMZD-0000 AG5A Deep Green
USCA-XXMC-DNZD-0000 AG5B Deep Green
USCA-XXMC-DOZD-0000 AG5C Deep Green
USCA-XXMC-TZCD-0000 STOUS Deep Green
USCA-XXMC-TZBD-0000 STOUP Deep Green
USCA-XXMC-TZDD-0000 STOUT Deep Green
USCA-XXMC-SZCD-0000 SBS Deep Green
USCA-XXMC-SZBD-0000 SBP Deep Green
USCA-XXMC-SZDD-0000 SBT Deep Green
USCA-XXMC-JZED-0000 BEV1 Deep Green
USCA-XXMC-JUCD-0000 BEV2S Deep Green
USCA-XXMC-JUBD-0000 BEV2P Deep Green
USCA-XXMC-NZZD-0000 E6 Deep Green
USCA-XXMC-PBZL-0000 ETOUB Light Green
USCA-XXMC-PCZL-0000 ETOUC Light Green
USCA-XXMC-PDZL-0000 ETOUD Light Green
USCA-XXMC-OZZL-0000 ELEC Light Green
31 RIN Rate Schedule Energy Supply
Product
USCA-XXMC-QAZL-0000 EVA Light Green
USCA-XXMC-QUZL-0000 EV2 Light Green
USCA-XXMC-AXZL-0000 A1X Light Green
USCA-XXMC-EZZL-0000 B1 Light Green
USCA-XXMC-ETZL-0000 B1ST Light Green
USCA-XXMC-CZZL-0000 A6 Light Green
USCA-XXMC-IZZL-0000 B6 Light Green
USCA-XXMC-BXCL-0000 A10SX Light Green
USCA-XXMC-FZCL-0000 B10S Light Green
USCA-XXMC-BXBL-0000 A10PX Light Green
USCA-XXMC-FZBL-0000 B10P Light Green
USCA-XXMC-BXDL-0000 A10TX Light Green
USCA-XXMC-FZDL-0000 B10T Light Green
USCA-XXMC-LZCL-0000 E19S Light Green
USCA-XXMC-GZCL-0000 B19S Light Green
USCA-XXMC-LZBL-0000 E19P Light Green
USCA-XXMC-GZBL-0000 B19P Light Green
USCA-XXMC-LZDL-0000 E19T Light Green
USCA-XXMC-GZDL-0000 B19T Light Green
USCA-XXMC-LRCL-0000 E19SR Light Green
USCA-XXMC-GRCL-0000 B19SR Light Green
USCA-XXMC-LRBL-0000 E19PR Light Green
USCA-XXMC-GRBL-0000 B19PR Light Green
USCA-XXMC-LRDL-0000 E19TR Light Green
USCA-XXMC-GRDL-0000 B19TR Light Green
USCA-XXMC-MZCL-0000 E20S Light Green
USCA-XXMC-HZCL-0000 B20S Light Green
USCA-XXMC-MZBL-0000 E20P Light Green
USCA-XXMC-HZBL-0000 B20P Light Green
USCA-XXMC-MZDL-0000 E20T Light Green
USCA-XXMC-HZDL-0000 B20T Light Green
USCA-XXMC-MRCL-0000 E20SR Light Green
USCA-XXMC-HRCL-0000 B20SR Light Green
USCA-XXMC-MRBL-0000 E20PR Light Green
USCA-XXMC-HRBL-0000 B20PR Light Green
USCA-XXMC-MRDL-0000 E20TR Light Green
USCA-XXMC-HRDL-0000 B20TR Light Green
USCA-XXMC-DAEL-0000 AGA1 Light Green
USCA-XXMC-DAFL-0000 AGA2 Light Green
USCA-XXMC-DBZL-0000 AGB Light Green
USCA-XXMC-DCZL-0000 AGC Light Green
32 RIN Rate Schedule Energy Supply
Product
USCA-XXMC-DGEL-0000 AGFA1 Light Green
USCA-XXMC-DGFL-0000 AGFA2 Light Green
USCA-XXMC-DGGL-0000 AGFA3 Light Green
USCA-XXMC-DHEL-0000 AGFB1 Light Green
USCA-XXMC-DHFL-0000 AGFB2 Light Green
USCA-XXMC-DHGL-0000 AGFB3 Light Green
USCA-XXMC-DIEL-0000 AGFC1 Light Green
USCA-XXMC-DIFL-0000 AGFC2 Light Green
USCA-XXMC-DIGL-0000 AGFC3 Light Green
USCA-XXMC-DJZL-0000 AG4A Light Green
USCA-XXMC-DKZL-0000 AG4B Light Green
USCA-XXMC-DLZL-0000 AG4C Light Green
USCA-XXMC-DMZL-0000 AG5A Light Green
USCA-XXMC-DNZL-0000 AG5B Light Green
USCA-XXMC-DOZL-0000 AG5C Light Green
USCA-XXMC-TZCL-0000 STOUS Light Green
USCA-XXMC-TZBL-0000 STOUP Light Green
USCA-XXMC-TZDL-0000 STOUT Light Green
USCA-XXMC-SZCL-0000 SBS Light Green
USCA-XXMC-SZBL-0000 SBP Light Green
USCA-XXMC-SZDL-0000 SBT Light Green
USCA-XXMC-JZEL-0000 BEV1 Light Green
USCA-XXMC-JUCL-0000 BEV2S Light Green
USCA-XXMC-JUBL-0000 BEV2P Light Green
USCA-XXMC-NZZL-0000 E6 Light Green
1 MARIN CLEAN ENERGY

LOAD MANAGEMENT STANDARDS PLAN

March 29Approved by MCE Board May 16, 2024

2 1 Table of Contents
1 Table of Contents 2
2 Introduction 4

2.1 About MCE 4

2.2 Load Management Standards 5

2.2.1 MCE LMS Plan and Board Authority 6
3 Access to Price Signals 9

3.1 Time-Dependent Rate Submission to MIDAS 9

3.1.1 Existing Rates Upload 9

3.1.2 Future Rates Upload 10

3.2 Plan to Provide Rate Identification Number(s) on Customer Billing Statements and Online Account Using Both Text and QR Code 10

3.3 Plans and Current Participation in the Development of Single Statewide RIN Access Tool 11
4 MCE Rates and Dynamic Rate Considerations 11

4.1 Overview of MCE’s Current Time-Dependent Rate Offerings 12

4.2 Dynamic Rates Evaluation 16

4.3 Dynamic Rate Development and Application Plan 21
5 Load Flexibility Programs 22

5.1 Overview of MCE Load Flexibility Programs 22

5.2 Evaluation of Programs 24

5.2.1 Cost Effectiveness 25

5.2.2 Equity 26

5.2.3 Technological Feasibility 26

5.2.4 Benefits to the Grid and Customers 27
6 Public Information Program 28
7 Appendix 30
1 Table of Contents 2
2 Introduction 44

2.1 About MCE 44

2.2 Load Management Standards 55

2.2.1 MCE LMS Plan and Board Authority 66
3 Access to Price Signals 99

3.1 Time-Dependent Rate Submission to MIDAS 99
3 3.1.1 Existing Rates Upload 99

3.1.2 Future Rates Upload 1010

3.2 Plan to Provide Rate Identification Number(s) on Customer Billing Statements and Online Account Using Both Text and QR Code 1010

3.3 Plans and Current Participation in the Development of Single Statewide RIN Access Tool – Amended July 2025 1111
4 MCE Rates and Dynamic Rate Considerations 1111

4.1 Overview of MCE’s Current Time-Dependent Rate Offerings 1212

4.2 Dynamic Rates Evaluation – Amended July 2025 1616

4.3 Dynamic Rate Development and Application Plan – Amended July 2025 2121 5 Load Flexibility Programs 2222

5.1 Overview of MCE Load Flexibility Programs 2322

5.2 Evaluation of Programs 2524

5.2.1 Cost Effectiveness 2525

5.2.2 Equity 2626

5.2.3 Technological Feasibility 2726

5.2.4 Benefits to the Grid and Customers 2827
6 Public Information Program 2828
7 Appendix 3030

4 2 Introduction

As a load-serving entity (“LSE”) MCE provides electricity generation service to approximately 580,000 customer accounts. These accounts represent more than one million residents and businesses across four Bay Area counties.1
MCE procures for annual retail sales of approximately
5,729 GWh and a peak load of more than 1,240 MW.

Figure 1: MCE Service Area Map
1 MCE serves communities across Contra Costa, Marin, Napa, and Solano counties. Those communities currently receiving service include: Unincorporated Contra Costa, Marin, Napa, and Solano counties and the Cities and Towns of Concord, Danville, El Cerrito, Lafayette, Martinez, Moraga, Oakley, Pinole, Pittsburg, Pleasant Hill, Richmond, San Pablo, San Ramon, Walnut Creek, Belvedere, Corte Madera, Fairfax, Larkspur, Mill Valley, Novato, Ross, San Anselmo, San Rafael, Sausalito, Tiburon, American Canyon, Calistoga, Napa, St. Helena, Yountville, Benicia, Vallejo, and Fairfield. MCE expects service to expand to include the City of Hercules in April of 2025. 5 As a JPA and local government agency, MCE is governed by a 34-member Board of Directors (“Board” or “Governing Board”) composed of elected representatives from MCE’s member communities. MCE’s Board sets policy for the agency and oversees operations, including rates and procurement planning. Through these representatives, MCE is controlled by and accountable to the communities MCE serves.

Specifically, the LMS request large CCAs to (1) develop and propose marginal cost-based rates that vary at least hourly3
or, (2) if the Board finds that implementing marginal cost-based hourly rates would not materially reduce peak load, be technologically feasible, and/or be cost-effective, offer a load flexibility program that allows at least one option for automating response to the CEC’s Market Informed Demand Automation Server (“MIDAS”) signals for customer classes where MCE’s Board determines such a program would materially reduce peak load and be cost-effective. For the purposes of this plan, MCE will refer to marginal cost-based rates that vary at least hourly as defined in the LMS as “hourly” or “dynamic” rates. 2 The LMS define Large CCAs as any CCA that provides in excess 700 GWh of electricity to customers in any calendar year.
3Section 1623.1(b)(1) of the LMS define a marginal cost-based rate as the sum of the marginal energy cost, the marginal capacity cost (generation, transmission, and distribution), and any other appropriate time and location dependent marginal costs, including the locational marginal cost of associated greenhouse gas emissions, on a time interval of no more than one hour.
6 2.2.1 MCE LMS Plan and Board Authority
Section 1623.1(a) requests each large CCA submit a plan outlining how it plans to meet the objectives of the LMS to its Board by April 1, 2024.

MCE notes that nothing in this plan overrides or supersedes MCE’s Board’s sole authority as the governing and rate-making body of MCE.5
Nothing in this plan implies any jurisdictional authority of the CEC over MCE’s rates and rate programs. MCE is currently voluntarily taking reasonable steps that meet the standards within the LMS regulations.

Accordingly, MCE submits this plan to the Board for adoption and approval to implement as outlined herein. Table 1 below provides a list of each regulatory standard or goal as outlined in the LMS and MCE’s plan to meet that standard or goal at the time of this writing. As described, MCE plans to continue to offer its portfolio of current and planned load flexibility programs and time dependent rates aimed at encouraging customers to use energy in off-peak hours, and will continue to explore how it may offer new cost-effective dynamic rates, pilots, and load flexibility programs that materially reduce peak load, encourage load control through automation, and provide reliability and environmental benefits for MCE customers and the California electric grid. 4 Consistent with Section 1623.1(a) of the LMS, MCE submitted this plan to its Board on March 29, 2024, and will submit this plan to the CEC within 30 days of Board approval. 5 Public Utilities Code Section 366.2(c)(3) provides that CCAs retain jurisdiction for setting rates for the electricity they purchase on behalf of their communities.
7 Table 1: MCE LMS Roadmap
Load Management
Standards Section Standard Description Target Date MCE Adopted Plan to Meet Standard §1623.1(c)
Upload existing time-dependent rates to
MIDAS database.

July 1, 2023
Status: Achieved
MCE plans to maintain future rates in
MIDAS to the extent it is cost
effective and technologically feasible.

The plan is to be
considered for adoption
by MCE’s Board within 60
days of submission at a
duly noticed public
meeting.

October 1,
2024
Status: In Progress
MCE is engaged in and monitoring
the development process for the
single statewide tool.
8 Load Management
Standards Section Standard Description Target Date MCE Adopted Plan to Meet Standard §1623.1(b)(3)
Submit to the CEC a list of
load flexibility programs
deemed cost effective by
MCE. The portfolio of
programs should provide
at least one option to
automate response to
MIDAS signals for each
customer class where
MCE’s Board has
determined such a
program would materially
reduce peak load.

July 1, 2025
Status: In Progress
At this time MCE cannot determine
that such a rate or will provide
material, incremental reductions to
peak load or be cost effective for any
customer class.

July 1, 2027
Status: To be determined by future
Board direction.

MCE notes that this target date is
after the next review of MCE’s LMS is
expected to be completed. As such,
MCE will likely provide an update in
its next LMS plan as appropriate.
9 Load Management
Standards Section Standard Description Target Date MCE Adopted Plan to Meet Standard §1623.1(b)(5)
Conduct a public
information program to
inform and educate
affected customers on
why marginal cost-based
rates or load flexibility
programs and automation
are needed, how they will
be used, and how these
rates and programs can
save customers money.

Once Every
Three Years
Status: MCE will review its LMS plan
at least once every three years
following the date of adoption.
3 Access to Price Signals

The period covered by the initial upload spanned between three and six months, due to data limitations of the MIDAS system. As such, MCE has made subsequent uploads to keep rates current in MIDAS:

1. In October 2023, MCE uploaded additional intervals to ensure all rates were up-to-date through December 31, 2023.
10 2. In November 2023, MCE uploaded additional intervals for all rates through May 1, 2024.6

MCE customers receive their consolidated billing statements from PG&E. MCE provides itemized charges to PG&E through Electronic Data Interchange (“EDI”) transactions. Therefore, MCE is reliant on PG&E to develop its EDI system to accept MCE RINs and display them on customer bills.
6 As of this writing, six of MCE’s Light Green rates are not current in the MIDAS system. These rates serve a small number of large Commercial & Industrial and EV customers with legacy 12p-6p peak periods. Upload attempts are rejected with the message, “An error has occurred.” MCE reached first reached out to CEC staff on November 30, 2023, and has had numerous, ongoing communications with CEC staff on this matter. The issue appears to reside with MIDAS, and not with MCE. CEC Staff has indicated they are aware of the issue, that it is not isolated to MCE and the CEC is working to resolve the issue. MCE will continue to engage and collaborate with the CEC in good faith to fix this issue.
11 CCAs have been working with PG&E to utilize PG&E’s billing transactions to include a CCA specific RIN on customers’ bills. MCE will supply MCE’s RIN mapping table to PG&E who will then include it within the code and display customers’ RINs on the generation portion of their bills. This interpretation has also been corroborated by PG&E in recent CPUC Advice Letters seeking approval to modify customers’ bill presentations to include RINs and QR codes.

MCE is monitoring and engaging in the process with the other regulated LSEs to develop a Single Statewide RIN Access Tool andpursuant to Adopted LMS Amendments Section 1623(c).

A proposed plan for the tool was submitted to the CEC for review on October 1, 2024. MCE will continue to collaborate with other parties onand the CEC towards the implementation and maintenance of the tool in a timely manner subject to the tool’s development ahead of the October 1, 2024, target date. At the time of this writingapproval by the CEC. MCE is unable to specifically identify the full scope and budget of integration of work; commit resources; or review, identify, and plan internal infrastructure needs until the Single Statewide Standard RIN Access Tool’s scope has been designed and approved by the CEC. 4 MCE Rates and Dynamic Rate Considerations
Adopted LMS Amendments Section 1623.1(a)(1) requests each large CCA to develop a plan that evaluates the cost-effectiveness, equity, technological feasibility, benefits to the grid, and benefits to customers of dynamic rates for each customer class. After evaluating dynamic rates, the CCA may instead propose and evaluate specified programs and/or delay or modify its implementation of the LMS.

Adopted LMS Amendments Section 1623.1(b)(2) requests MCE apply to its rate-approving body for approval of at least one dynamic rate by July 1, 2025. The LMS state MCE is to apply for approval only of a dynamic rate only for those customer classes for which the Board determines such a rate will materially reduce peak load.
12 Adopted LMS Amendments Section 1623.1(b)(4) requests each CCA to offer to each of its electricity customers voluntary participation in either a dynamic rate developed according to Section 1623.1(b)(2), if such rate is approved by the Board, or a cost-effective load flexibility program that allows automated response to MIDAS signals for each customer class the Board determines such a program would materially reduce peak load July 1, 2027.

This section provides an overview of MCE’s current time-dependent rates and its plan to evaluate and develop dynamic rates as stated in the LMS.

MCE also offers a wide range of options for time-dependent pricing for non-residential customers as depicted in Table 3 below. Except in rare circumstances like street lighting, non-residential service is entirely billed according to time-dependent pricing. All of MCE’s 7 A complete list of MCE Residential rates can be found at https://www.mcecleanenergy.org/rates/. 13 non-residential rates have 4pm-9pm daily peak and seasonal rates, except where noted otherwise.

Table 3: Current MCE Non-Residential Rate Offerings8
MCE Non-Residential Rates Description of Rate Periods
B-1 - Small General Service Utilizes six TOU periods (three in the Summer and three in the Winter)
B-1ST - Small General Service
Plus Storage
Utilizes seven TOU periods (three in the
Summer and four in the Winter)
B-6 - Small General Service
Utilizes five TOU periods (two in the
Summer and three in the Winter) and
stronger pricing signals relative to rate
schedule B-1
B-10 - Medium General
Service
Utilizes six TOU periods (three in the
Summer and three in the Winter) and
three voltage levels with discrete rates
B-19 - Medium General
Service
Utilizes six TOU periods (three in the
Summer and three in the Winter), TOU
and seasonal based demand charges, and
three voltage levels with discrete rates
B-19 Option R - Medium
General Service for Solar
Utilizes six TOU periods (three in the
Summer and three in the Winter), no
demand charges, and three voltage levels
with discrete rates
B-20 Option R - Large General
Service for Solar
Utilizes six TOU periods (three in the
Summer and three in the Winter), no
demand charges, and three voltage levels
with discrete rates
BEV - Commercial EV
Charging
Utilizes three TOU periods, no
seasonality, and three voltage levels with
discrete rates
AG-A - Small Agriculture
Utilizes four TOU periods (two in the
Summer and two in the Winter), and uses
a 5pm-8pm peak pricing period
8 A complete list of MCE Non-Residential rates can be found at https://www.mcecleanenergy.org/commercial-rates/. 14 MCE Non-Residential Rates Description of Rate Periods AG-B - Medium Agriculture
Utilizes four TOU periods (two in the
Summer and two in the Winter), 5pm-8pm peak pricing period AG-C - Large Agriculture
Utilizes four TOU periods (two in the
Summer and two in the Winter), 5p-8p
peak, summer peak demand
AG-F - Flexible TOU
Agriculture
Utilizes AG-A/AG-B/AG-C variations as
above, with two designated 24-hour off-peak days
SB - Standby Service
Utilizes six TOU periods (three in the
Summer and three in the Winter), a
reservation charge per kW, and three
voltage levels with discrete rates
SL-1 - Street, Highway, and
Outdoor Lighting This rate is not time dependent
TC-1 - Traffic Control Service This rate is not time dependent MCE also continues to offer limited service to legacy non-residential rate schedules without a 4pm-9pm peak. Eligibility is determined by PG&E according to tariffs approved by the CPUC.

Table 4: MCE Legacy Rates
MCE Legacy Rates Description of Rate Periods
A-1 - Small General Service This is a non-TOU rate
A-1X - Small General Service Utilizes five TOU periods (three in the Summer and two in the Winter)
A-6 - Small General Service Utilizes five TOU periods (three in the Summer and two in the Winter)
A-10 - Medium General Service This is a non-TOU rate but includes three voltage levels with discrete rates
15 MCE Legacy Rates Description of Rate Periods
A-10X - Medium General Service
Utilizes five TOU periods (three in the
Summer and two in the Winter) and
three voltage levels with discrete rates
E-19 - Medium General Service
Utilizes five TOU periods (three in the
Summer and two in the Winter), demand
charges, and three voltage levels with
discrete rates
E-20 - Large General Service
Utilizes five TOU periods (three in the
Summer and two in the Winter), and
three voltage levels with discrete rates
E-20 Option R - Large General
Service for Solar Customers
Utilizes five TOU periods (three in the
Summer and two in the Winter), and
three voltage levels with discrete rates
AG-1 - Small Agricultural Service This is a non-TOU rate AG-4-A - Time-of-Use Agricultural
Service
Time-of-Use Agricultural Service:

Includes four TOU periods (two in the
Summer and two in the Winter) and a
connected load charge
AG-4-B - Time-of-Use Agricultural
Service
Utilizes four TOU periods (two in the
Summer and two in the Winter) and a
maximum demand charge
AG-4-C - Time-of-Use Agricultural
Service
Utilizes five TOU periods (three in the
Summer and two in the Winter) and a
peak demand charge
AG-5-A - Time-of-Use Agricultural
Service
Utilizes four TOU periods (two in the
Summer and two in the Winter) and a
connected load charge
AG-5-B - Time-of-Use Agricultural
Service
Utilizes four TOU periods (two in the
Summer and two in the Winter) and a
maximum demand charge
AG-5-C - Time-of-Use Agricultural
Service
Utilizes five TOU periods (three in the
Summer and two in the Winter) and a
peak demand charge
AG-R - Time-of-Use Agricultural
Service with Off Peak Days
Utilizes four TOU periods (two in the
Summer and two in the Winter), two day-
16 MCE Legacy Rates Description of Rate Periods
of-week options, two service levels, and
connected load or demand charges
AG-R - Time-of-Use Agricultural
Service with Variable Peak
Utilizes four TOU periods (three in the
Summer and two in the Winter), three
peak hour options, two service levels,
and connected load or demand charges
S - Standby Service
Utilizes five TOU periods (three in the
Summer and two in the Winter),
reservation charge per kW, and three
voltage levels with discrete rates
MCE also offers two energy supply programs that are charged or credited to the customer’s energy bill but separate from each customer’s electric rate schedule:
● Deep Green Service: This program allows customers to choose 100 percent renewable energy content and includes a $0.01/kWh flat adder to all rates. ● Disadvantaged Communities Green Tariff (“DAC-GT”): This program allows eligible customers in disadvantaged communities to choose 100 percent renewable energy content and receive a 20 percent total bill discount.

While MCE has not yet offered any dynamic rates or dynamic rate pilots, MCE understands that there may be value in suchdynamic rates or dynamic rate pilots, and is currently evaluating 17 whether it may offer one ofoffering all the dynamic rate pilots approved by the CPUC for PG&E’s service area9 or whether it may proposeas well as offering its own, distinct dynamic EV rate pilot(s) to its customers, which wouldMCE Sync Dynamic Rewards.10 These pilots should allow MCE to collect the data necessary to evaluate the cost-effectiveness, equity, feasibility, and customer and grid benefits of such rates to inform MCE’s future rate designs and offerings. Generally, MCE notes that it has a preference to create and offer MCE specific rates, pilots, and programs that can be uniquely tailored and administered by MCE to meet the needs of its customers, which may be distinct from other regions of PG&E’s service area and rely on MCE’s significantly clean and GHG-free portfolio in the California Independent System Operator markets.

PotentialOffering dynamic rate pilots should provide necessary and useful data to evaluate and determine the appropriateness (and potential design) of future dynamic rate offerings in MCE’s service area.

As discussed below MCE does not at this timeIn the version of this plan approved by the Board on May 16, 2024, MCE found that it did not have sufficient evidence to conclude that developing and implementing dynamic rates in MCE’s service area on the timeline outlined in the LMS would be cost effective or provide material incremental reductions to peak load beyond those of its current rate and programs portfolio for any customer class. As such MCE cannot currentlyThe Board-approved plan found it necessary to modify Section 1623.1(b)(2)’s request for MCE to apply for approval of a dynamic rate by July 1, 2025. The Board-approved plan concluded that the timeline must be modified to ensure cost-effective implementation and that MCE Staff may, but was not required to, propose such a rate to the Board by the target date of July 1, 2025. At that time, MCE could not commit to creating such a rate for Board approval by July 1, 2025.

However, MCE is interested in collecting the data necessary to make such determinations and is exploring options to offernow offering dynamic rate pilots in its service territory. MCE therefore recommendsbegan offering the Board find it necessary to modify Section 1623.1(b)(2)’s request for MCE to apply for approval of a Sync Dynamic Rewards pilot in September 2024, and on April 4, 2025, MCE’s Board approved MCE’s participation in the dynamic rate by July 1, 2025. MCE recommends the Board conclude that pilots offered in PG&E’s service area: Expanded Pilot 1, Expanded Pilot 2, and the VGI-Commercial Pilot, and therefore has met the original timeline must be modified to ensure cost-effective implementation and determine that MCE Staff may, but is not required to, propose such a rate to the Board by the target date of July 1, 9 For example, California Public Utilities Commission Decision (D) 24-01-032 approved the expansion of two demand flexibility pilots in PG&E's service area that would allow CCA participation. Under the Transportation Electrification Rulemaking 18-12-006, the CPUC further authorized PG&E’s vehicle-to-grid (VGI) pilots with a dynamic rate that allow CCA participation. MCE is currently evaluating whether it may participate beginning in the Summer of 2025offering all three pilots to its customers. 10 The MCE Sync Dynamic Rewards pilot allows customers the chance to receive additional savings in MCE Sync by responding to dynamic hourly price signals (based on day-ahead CAISO prices for the PG&E Default Load Aggregation Point (DLAP). Customers who enroll in the dynamic pilot will receive an enrollment bonus of $50 and then receive a monthly reward payment for allowing MCE Sync to charge their car according to the dynamic price signal.
18 2025.adopted in Section 1623.1(b)(2). MCE will provide updates to its Board in its next plan iteration and any annual reports.
a. Cost-Effectiveness
In determining whether to offer dynamic rates that vary at least hourly as outlined in the LMS, one evaluation factor that MCE will consider is cost-effectiveness.

MCE notes that the CEC’s adopted LMS state there shall be no reimbursement to local government agencies for the costs of carrying out the Standards as the Commission has found them to be cost effective, noting that savings realized will outweigh the costs associated with implementing the programs.11 While MCE appreciates the plain language of the LMS, MCE disagrees that the cost-effectiveness of any rates or programs could be determined before those rates or programs actually exist. At this point there exists no evidence to conclude that MCE will realize any net savings from implementing the LMS. MCE has not yet offered anyIt is too early in MCE’s offering of hourly or dynamic rates or pilot programs to allow for sufficient analysis of the effectiveness (cost or otherwise) of dynamic rates in its service area. MCE has so far incurred only costs associated with the LMS and any benefits remain to be realized.

At presentAs of September 2024, MCE is exploring the possibility of creatingimplemented an hourly rate pilot for its electric vehicle (“EV”) customers, as well asMCE Sync Dynamic Rewards.12 MCE is also participating in, monitoring, and evaluating the status of CPUC approved PG&E dynamic rate pilots and considering participation for Summer 2025. However, without such primary data, MCE cannot at this time determine that such a rate or program will provide material incremental reductions to peak load or be cost effective for any customer class.

MCE will continue to evaluate whether to offer future dynamic rate pilots and rates to its customers and will evaluate the results of any its own pilot and the pilots in PG&E’s service area.

To the extent MCE does participate in or offer dynamic rate pilots, MCE will use the pilot(s)pilots as an opportunity to collect the data necessary to conduct its own cost-effectiveness analysis with MCE specific data, which would be used to inform future rate and program offerings as well as future iterations of MCE’s LMS Plan.

In developing dynamic rates with the goal of encouraging customers to change their behavior and shift their energy consumption away from peak hours, one of MCE’s goals will be to minimize the amount of cost shifting that occurs between customers, particularly due to structural benefactors. To do so, MCE will aim to ensure that customers on hourly rates are sufficiently able to respond to price signals, whether through automation and/or price signals that are strong enough to incent behavioral change.

Local grid constraints vary based on grid infrastructure, design, and capacity constraints that are generally outside of any individual customer’s control. The more locational granularity in rates, the more potential there is for equity issues to arise. To address this issue, evaluation should be done to ensure that dynamic pricing based on localized grid constraints does not particularly burden low-income residents or those in disadvantaged communities. MCE does not currently have data on how more granular locational variation in rates may impact equity but urges all California LSEs as well as the CEC and CPUC to work to ensure that certain customers are not unfairly harmed by future rate design simply due to their location on the grid. c. Technological Feasibility
13 This is at least true in the short-term. However, in the long-term material reductions/changes in behavior may lower the total revenue requirement and those cost savings could be passed through to all customers. 21 MCE expects that it is technically feasible to offer a dynamic hourly generation rate option by July 1, 2027, as outlined in the LMS, contingent upon PG&E providing revenue quality billing data to MCE on an hourly level or developing a reliable workaround. Current PG&E billing transactions do not include the hourly interval data which would be matched against hourly dynamic prices. MCE hopes that as PG&E develops CPUC approved hourly pricing pilots, this data will become available.

MCE notes that even if dynamic rates are technically feasible, daily rate uploads to MIDAS will need to be supported by the development of new systems, which may delay or otherwise impede offering dynamic rates in the near term. The limitations of the current MIDAS system and the lack of funding for LSEs to develop systems for interacting with MIDAS may mean that it will not be cost effective or feasible to maintain dynamic rates in MIDAS at this time. d. Benefits to the Grid and Customers
MCE will also consider benefits to the grid and benefits to customers in its evaluation of dynamic rates. Assuming material changes in energy consumption behavior by customers, potential grid benefits resulting from hourly rates include but are not limited to reliability benefits, deferred, and reduced grid infrastructure investments, and environmental benefits.

MCE is committed to exploring options for offering dynamic rate offerings to customers, but at this time cannot determine that such rates would provide material incremental reductions to peak load, provide other material benefits to MCE or its customers, or be cost effective for any customer class. In evaluating future potential dynamic rates MCE will consider whether or how any dynamic rate is expected to: 1) drive behavioral change; 2) be cost effective; 3) impact equity outcomes; and 4) provide reliable incremental benefits relative to MCE’s current rate offerings. 22 At presentAs of September 2024, MCE is exploring the possibility of began offering a dynamic rate pilot, MCE Sync Dynamic Rewards, for its electric vehicle (“EV”) customers, as well as. MCE is also participating in, monitoring, and evaluating the status of CPUC approved PG&E dynamic rate pilots and considering participation for Summer 2025. However, without such primary data, MCE cannot at this time determine that such a rate or program will provide material incremental reductions to peak load or be cost effective for any customer class.

This section of MCE’s Plan provides an overview of MCE’s current load flexibility programs and addresses how MCE will evaluate and propose specified programs on the timeframes set forth in the LMS.
23 5.1 Overview of MCE Load Flexibility Programs
Residential Programs
MCE Sync
MCE Sync is an MCE-funded Automated Load Management program that utilizes a smart charging app to reduce EV owner’s charging load during peak times, while also seeking to align EV charging load with high-solar daytime hours.14 MCE began offering MCE Sync to eligible customers in 2021 and the program offers customers a flat monthly credit for participating in events.

Richmond Virtual Power Plant (VPP) Pilot
MCE is working to launch an innovative VPP pilot in Richmond, California, which will provide bill savings and increase local grid reliability, safety, and efficiency for low-income residents as part of Richmond’s Advanced Energy Community project.16 The VPP pilot includes $8 million in funding from the CEC and will provide a suite of clean distributed energy resources (“DERs”) targeting low-income households in Richmond for dispatchability, flexibility, and resiliency purposes.
14 See https://www.mcecleanenergy.org/mce-sync/. 15 See https://www.mcecleanenergy.org/peak-flexmarket/. 16 See http://mcecleanenergy.org/vpp. 24 MCE’s Richmond VPP Pilot is expected to provide significant bill savings for customers and significant local and grid benefits. MCE currently expects the pilot to launch in 2025.

Residential Efficiency Market
MCE’s Residential Efficiency Market program is focused on incentivizing customers to install measures that can help reduce peak load.17 Customers can receive a 20 percent upfront cash payment for the forecasted value of their energy efficiency projects and additional payments for metered savings of those energy efficiency projects.

Customers are eligible to receive up to $20/month for participation based on their solar system’s size.

Commercial Efficiency Market
MCE’s Commercial Efficiency Market program is focused on incentivizing non-residential customers to install measures that can help reduce peak load.19 Customers can receive a 20 percent upfront cash payment for the forecasted value of their energy efficiency projects and additional payments for metered savings of those energy efficiency projects. 17 See https://www.mcecleanenergy.org/flexmarket/. 18 See https://www.mcecleanenergy.org/solar-storage-credit/. 19 See https://www.mcecleanenergy.org/flexmarket/. 25 5.2 Evaluation of Programs
This section evaluates the cost-effectiveness, equity, technological feasibility, and benefits to the grid and customers of implementing programs that enable automated response to MIDAS signals. As discussed below, MCE cannot currently conclude that creating a new, or modifying an existing, load-modifying program to allow automated responses to MIDAS signals would be cost effective or offer material incremental benefit, such as material incremental peak load reduction, for any customer class.

Accordingly, MCE will continue to offer voluntary participation in its existing and future load flexibility programs. MCE will continue to consider the cost-effectiveness and peak load reduction potential of programs that enable automated response to MIDAS signals. To the extent that MCE’s Board does not approve a dynamic rate offering by 2027, and MCE is at that time able to determine that modifying an existing program or creating a new program that enables automated response to MIDAS signals is cost effective and provides material incremental reductions to peak load for at least one customer class, MCE may at that time integrate a load-modifying program into MIDAS.

1. Peak FLEXmarket;

2. Commercial Efficiency Market; and

3. Residential Efficiency Market.

As it relates to the cost-effectiveness of MCE’s current and future self-funded and/or grant-funded load-modifying programs (MCE Sync, Solar Storage Credit, Richmond VPP Pilot, etc.) MCE has not yet evaluated these programs for cost-effectiveness in the same manner as its ratepayer funded energy efficiency programs. Generally, MCE notes that cost-effectiveness is just one measure used to determine whether to offer a program and is not necessarily a determining factor. For example, programs that are focused on providing equity benefits may not be cost-effective utilizing traditional cost-effectiveness evaluation criteria, but still provide significant benefit to certain customer segments and society at large. MCE may robustly evaluate these programs for cost-effectiveness in the future when evaluating the effectiveness of the programs, and as it makes future determinations on program offerings. 26 MCE does not currently expect to utilize program offerings with automated responses to MIDAS signals; however, if MCE’s Board does not adopt an hourly rate by July 1, 2027, MCE may then evaluate whether there is an opportunity to create a new program or modify an existing program to allow responses to MIDAS signals. In doing so, MCE would look at the incremental value of each option, and if modifying an existing, or creating a new, program is deemed cost-effective and found to provide material reductions to peak load may elect to do so at that time.

While these costs could potentially be offset with capacity or energy cost savings, the magnitude of those benefits is uncertain.

1. Income-qualified customer programs such as the Low-Income Families and Tenants Program, the MCE Cares Credit Program, DAC-GT program, and EV Rebate Program;

2. Commercial Equity Program;

3. Commitment to advancing supplier diversity and workforce development; and

4. MCE’s Community Power Coalition.20
In evaluating any future load-modifying program offerings, MCE will plan to evaluate how that offering may impact customer equity. Potential evaluation criteria include, but are not limited to, equitable access to technology, direct customer benefits and bill impacts, and cost-shifting between and within rate classes. For example, most customers’ ability to benefit from highly differentiated rates will be directly linked to their ability to respond to those rates. Customers that can automate portions of their load will be best equipped to respond and benefit. Therefore, equitable access to automation devices and technology will be critical in ensuring that all 20 More information on MCE’s energy equity efforts can be found on its website at https://www.mcecleanenergy.org/energy-equity/#energyequity. 27 customers can benefit from load-modifying programs. To promote equitable access to automation technology MCE may explore providing additional incentives for low-income customers and/or those who located in disadvantaged communities or multi-family properties who may otherwise not be able to benefit from automated load shifting programs or dynamic rates.

5.2.3 Technological Feasibility
MCE is committed to offering load-modifying programs that encourage customers to shift their load away from periods of grid constraint and high greenhouse gas emissions. MCE strongly supports the LMS’ goals to provide customers and their devices access to signals that may help automate their response to marginal signals such as prices and greenhouse gas signals to provide the greatest level of benefit for both the customer and the grid. MCE has demonstrated this support through the development of its MCE Sync EV charging mobile application and the MCE Peak FLEXmarket platform, both of which are technology platforms that help customers adjust their energy consumption through greater visibility. And while MCE believes it is technically feasible to offer customers programs that allow customers to respond to MIDAS signals, currently, both of these load-modifying programs are incompatible with the MIDAS database, and MCE cannot conclude that modifying them to be compatible would be cost effective or result in material incremental load reduction:21 ● MCE Sync - This program provides a flat monthly credit to customers for participating in events, and does not have rates associated with events, and thus would not support inclusion in MIDAS.
● PeakFLEX Market - There is currently no way for MIDAS to show customers their current real-time rate for this program, as it is based on separate prices (baseline and above-baseline) that depend on a customers’ individual usage history, which is not a component of MIDAS.

As MCE’s existing load-modifying programs are not currently technologically compatible with MIDAS, if MCE at a later date elects to work towards the goals of the LMS via a MIDAS enabled program offering MCE would need to determine how it could either integrate its existing programs with MIDAS or explore the creation of a new program that would be compatible with the current or future design of MIDAS. Such determinations will need to be made by the Board at a future date.
21 While not a load-modifying program, MCE also notes that its Disadvantaged Community Green Tariff program is also not included in MIDAS currently as it is not compatible with the current design of MIDAS. The 20 percent bill discount for the DAC-GT program is calculated from a customer’s total billed charges, inclusive of non-volumetric and variable IOU charges, by reading the total charges from the previous bill. As such, MCE cannot generate a volumetric price inclusive of this discount.
28 5.2.4 Benefits to the Grid and Customers
In considering whether to modify existing or offer new load-modifying programs, including those that allow automated response to MIDAS signals, MCE may consider benefits to the grid and customers.

All of these potential grid and customer benefits depend on the reliability and magnitude of load shift and reduction that load-modifying programs are able to achieve. MCE is at this time unable to conclude that future programs or modifications to existing programs to allow automated responses to MIDAS signals would result in material grid benefits relative to MCE’s existing offerings or result in pass through savings to customers for any customer class. If MCE creates a load-modifying program that allows automated response to MIDAS signals in the future it will aim to design the program in such a way to generate material benefits to the grid and MCE customers.
6 Public Information Program
Adopted LMS Amendments Section 1623.1(b)(5) of the LMS requests MCE and other Large CCAs to conduct a public information program to inform and educate affected customers on why dynamic rates or load flexibility programs and automation are needed, how they will be used, and how these rates and programs can save customers money.

As a general matter, all MCE rates and programs can be found on MCE’s website. Any future dynamic rates or load-modifying programs will also be listed and described on its webpage.22 MCE utilizes best practices to provide consistent and accurate communications and response support with its customers and communities. This includes utilizing various communication mediums including joint rate mailers, emails, direct mail, e-newsletters, press releases, webinars, 22 MCE Residential rates can be viewed at https://www.mcecleanenergy.org/rates/. MCE Commercial rates can be viewed at https://www.mcecleanenergy.org/commercial-rates/. MCE program offerings can be found at https://www.mcecleanenergy.org/customer-programs/.
29 social media posts, public presentations and event attendance and sponsorship throughout MCE’s member communities. In 2023 alone, MCE attended more than 250 events in our service area and presented to 69 local community organizations and city councils. MCE plans to continue communication best practices to maintain its outreach, education, and marketing of rates, programs, and pilots that support load flexibility and recognize the benefits of reducing peak load and using energy during periods of higher renewables supply. In addition, MCE has developed an in-house service center to support and effectively respond to customer inquiries and further the education and benefits of load-modifying programs.

Historically, MCE has voluntarily utilized various types of marketing campaigns to drive enrollment and successful participation in rate and program offerings including those created for load-modifying purposes. For example, to encourage customers to shift load on Time-of-Use rates, MCE conducted a public information campaign that included direct mail, website updates, digital advertising, streaming, and radio placement encouraging customers to use less energy during the 4pm - 9pm peak period targeted to customers throughout MCE’s service area.23 MCE notes that the LMS do not include a timeline for the public information campaign. As there is no timeline expressed in the Standards and MCE has not created or recommended Board approval of any new hourly marginal cost-based rates or programs that allow automated response to MIDAS signals, MCE does not have details on what future public information programs may entail. MCE expects that if dynamic rates or new load flexibility programs are adopted MCE would utilize a public information program to drive customer adoption, understanding, and success in said rates or programs.

MCE expects that any public information campaign would require incremental costs that are not currently accounted for, and MCE would need to factor these public information and response program costs and their recovery into any cost-effectiveness analysis and recommendation to its Board.
23 See https://www.mcecleanenergy.org/4-9/.
30 7 Appendix
Appendix A – MCE MIDAS Rate Identification Numbers
The below table displays the RINs associated with each of MCE's residential and non-residential rates and rate permutations that have been uploaded to MIDAS.

RIN Rate Schedule Energy Supply
Product
USCA-XXMC-PBZD-0000 ETOUB Deep Green
USCA-XXMC-PCZD-0000 ETOUC Deep Green
USCA-XXMC-PDZD-0000 ETOUD Deep Green
USCA-XXMC-OZZD-0000 ELEC Deep Green
USCA-XXMC-QAZD-0000 EVA Deep Green
USCA-XXMC-QUZD-0000 EV2 Deep Green
USCA-XXMC-AXZD-0000 A1X Deep Green
USCA-XXMC-EZZD-0000 B1 Deep Green
USCA-XXMC-ETZD-0000 B1ST Deep Green
USCA-XXMC-CZZD-0000 A6 Deep Green
USCA-XXMC-IZZD-0000 B6 Deep Green
USCA-XXMC-BXCD-0000 A10SX Deep Green
USCA-XXMC-FZCD-0000 B10S Deep Green
USCA-XXMC-BXBD-0000 A10PX Deep Green
USCA-XXMC-FZBD-0000 B10P Deep Green
USCA-XXMC-BXDD-0000 A10TX Deep Green
USCA-XXMC-FZDD-0000 B10T Deep Green
USCA-XXMC-LZCD-0000 E19S Deep Green
USCA-XXMC-GZCD-0000 B19S Deep Green
USCA-XXMC-LZBD-0000 E19P Deep Green
USCA-XXMC-GZBD-0000 B19P Deep Green
USCA-XXMC-LZDD-0000 E19T Deep Green
USCA-XXMC-GZDD-0000 B19T Deep Green
USCA-XXMC-LRCD-0000 E19SR Deep Green
USCA-XXMC-GRCD-0000 B19SR Deep Green
USCA-XXMC-LRBD-0000 E19PR Deep Green
USCA-XXMC-GRBD-0000 B19PR Deep Green
USCA-XXMC-LRDD-0000 E19TR Deep Green
USCA-XXMC-GRDD-0000 B19TR Deep Green
USCA-XXMC-MZCD-0000 E20S Deep Green
USCA-XXMC-HZCD-0000 B20S Deep Green
USCA-XXMC-MZBD-0000 E20P Deep Green
USCA-XXMC-HZBD-0000 B20P Deep Green
31 RIN Rate Schedule Energy Supply
Product
USCA-XXMC-MZDD-0000 E20T Deep Green
USCA-XXMC-HZDD-0000 B20T Deep Green
USCA-XXMC-MRCD-0000 E20SR Deep Green
USCA-XXMC-HRCD-0000 B20SR Deep Green
USCA-XXMC-MRBD-0000 E20PR Deep Green
USCA-XXMC-HRBD-0000 B20PR Deep Green
USCA-XXMC-MRDD-0000 E20TR Deep Green
USCA-XXMC-HRDD-0000 B20TR Deep Green
USCA-XXMC-DAED-0000 AGA1 Deep Green
USCA-XXMC-DAFD-0000 AGA2 Deep Green
USCA-XXMC-DBZD-0000 AGB Deep Green
USCA-XXMC-DCZD-0000 AGC Deep Green
USCA-XXMC-DGED-0000 AGFA1 Deep Green
USCA-XXMC-DGFD-0000 AGFA2 Deep Green
USCA-XXMC-DGGD-0000 AGFA3 Deep Green
USCA-XXMC-DHED-0000 AGFB1 Deep Green
USCA-XXMC-DHFD-0000 AGFB2 Deep Green
USCA-XXMC-DHGD-0000 AGFB3 Deep Green
USCA-XXMC-DIED-0000 AGFC1 Deep Green
USCA-XXMC-DIFD-0000 AGFC2 Deep Green
USCA-XXMC-DIGD-0000 AGFC3 Deep Green
USCA-XXMC-DJZD-0000 AG4A Deep Green
USCA-XXMC-DKZD-0000 AG4B Deep Green
USCA-XXMC-DLZD-0000 AG4C Deep Green
USCA-XXMC-DMZD-0000 AG5A Deep Green
USCA-XXMC-DNZD-0000 AG5B Deep Green
USCA-XXMC-DOZD-0000 AG5C Deep Green
USCA-XXMC-TZCD-0000 STOUS Deep Green
USCA-XXMC-TZBD-0000 STOUP Deep Green
USCA-XXMC-TZDD-0000 STOUT Deep Green
USCA-XXMC-SZCD-0000 SBS Deep Green
USCA-XXMC-SZBD-0000 SBP Deep Green
USCA-XXMC-SZDD-0000 SBT Deep Green
USCA-XXMC-JZED-0000 BEV1 Deep Green
USCA-XXMC-JUCD-0000 BEV2S Deep Green
USCA-XXMC-JUBD-0000 BEV2P Deep Green
USCA-XXMC-NZZD-0000 E6 Deep Green
USCA-XXMC-PBZL-0000 ETOUB Light Green
USCA-XXMC-PCZL-0000 ETOUC Light Green
USCA-XXMC-PDZL-0000 ETOUD Light Green
USCA-XXMC-OZZL-0000 ELEC Light Green
32 RIN Rate Schedule Energy Supply
Product
USCA-XXMC-QAZL-0000 EVA Light Green
USCA-XXMC-QUZL-0000 EV2 Light Green
USCA-XXMC-AXZL-0000 A1X Light Green
USCA-XXMC-EZZL-0000 B1 Light Green
USCA-XXMC-ETZL-0000 B1ST Light Green
USCA-XXMC-CZZL-0000 A6 Light Green
USCA-XXMC-IZZL-0000 B6 Light Green
USCA-XXMC-BXCL-0000 A10SX Light Green
USCA-XXMC-FZCL-0000 B10S Light Green
USCA-XXMC-BXBL-0000 A10PX Light Green
USCA-XXMC-FZBL-0000 B10P Light Green
USCA-XXMC-BXDL-0000 A10TX Light Green
USCA-XXMC-FZDL-0000 B10T Light Green
USCA-XXMC-LZCL-0000 E19S Light Green
USCA-XXMC-GZCL-0000 B19S Light Green
USCA-XXMC-LZBL-0000 E19P Light Green
USCA-XXMC-GZBL-0000 B19P Light Green
USCA-XXMC-LZDL-0000 E19T Light Green
USCA-XXMC-GZDL-0000 B19T Light Green
USCA-XXMC-LRCL-0000 E19SR Light Green
USCA-XXMC-GRCL-0000 B19SR Light Green
USCA-XXMC-LRBL-0000 E19PR Light Green
USCA-XXMC-GRBL-0000 B19PR Light Green
USCA-XXMC-LRDL-0000 E19TR Light Green
USCA-XXMC-GRDL-0000 B19TR Light Green
USCA-XXMC-MZCL-0000 E20S Light Green
USCA-XXMC-HZCL-0000 B20S Light Green
USCA-XXMC-MZBL-0000 E20P Light Green
USCA-XXMC-HZBL-0000 B20P Light Green
USCA-XXMC-MZDL-0000 E20T Light Green
USCA-XXMC-HZDL-0000 B20T Light Green
USCA-XXMC-MRCL-0000 E20SR Light Green
USCA-XXMC-HRCL-0000 B20SR Light Green
USCA-XXMC-MRBL-0000 E20PR Light Green
USCA-XXMC-HRBL-0000 B20PR Light Green
USCA-XXMC-MRDL-0000 E20TR Light Green
USCA-XXMC-HRDL-0000 B20TR Light Green
USCA-XXMC-DAEL-0000 AGA1 Light Green
USCA-XXMC-DAFL-0000 AGA2 Light Green
USCA-XXMC-DBZL-0000 AGB Light Green
USCA-XXMC-DCZL-0000 AGC Light Green
33 RIN Rate Schedule Energy Supply
Product
USCA-XXMC-DGEL-0000 AGFA1 Light Green
USCA-XXMC-DGFL-0000 AGFA2 Light Green
USCA-XXMC-DGGL-0000 AGFA3 Light Green
USCA-XXMC-DHEL-0000 AGFB1 Light Green
USCA-XXMC-DHFL-0000 AGFB2 Light Green
USCA-XXMC-DHGL-0000 AGFB3 Light Green
USCA-XXMC-DIEL-0000 AGFC1 Light Green
USCA-XXMC-DIFL-0000 AGFC2 Light Green
USCA-XXMC-DIGL-0000 AGFC3 Light Green
USCA-XXMC-DJZL-0000 AG4A Light Green
USCA-XXMC-DKZL-0000 AG4B Light Green
USCA-XXMC-DLZL-0000 AG4C Light Green
USCA-XXMC-DMZL-0000 AG5A Light Green
USCA-XXMC-DNZL-0000 AG5B Light Green
USCA-XXMC-DOZL-0000 AG5C Light Green
USCA-XXMC-TZCL-0000 STOUS Light Green
USCA-XXMC-TZBL-0000 STOUP Light Green
USCA-XXMC-TZDL-0000 STOUT Light Green
USCA-XXMC-SZCL-0000 SBS Light Green
USCA-XXMC-SZBL-0000 SBP Light Green
USCA-XXMC-SZDL-0000 SBT Light Green
USCA-XXMC-JZEL-0000 BEV1 Light Green
USCA-XXMC-JUCL-0000 BEV2S Light Green
USCA-XXMC-JUBL-0000 BEV2P Light Green
USCA-XXMC-NZZL-0000 E6 Light Green
July 17, 2025
TO: MCE Board of Directors
FROM: Alexandra McGee, Vice President of Strategic Initiatives Catalina Murphy, General Counsel
RE: Proposed Resolution 2025-04 Authorizing the CEO to Negotiate and Execute Vendor Services Agreements with Community Energy and Equity Resources LLC, Serious Controls LLC, and Lawrence Berkeley National Laboratory for MCE’s Virtual Power Plant Program Supported by Funding from the California Energy Commission (Agenda Item #05 C.6) ATTACHMENT: Resolution 2025-04 Authorizing the CEO to Negotiate and Execute Vendor Services Agreements with Community Energy and Equity Resources LLC, Serious Controls LLC, and Lawrence Berkeley National Laboratory for MCE’s Virtual Power Plant Program Supported by Funding from the California Energy Commission
Dear Board Members:

Summary:

In February 2025, your Board accepted the grant MCE was awarded from the California Energy Commission (CEC) in the amount of $5,000,000 with MCE matching an additional $5,000,000 to advance MCE’s Virtual Power Plant (VPP) initiative aimed at creating a cleaner, more reliable electric grid (the Grant). Since your Board accepted the Grant, staff has worked with the CEC to finalize the Grant contract and work with the Grant partners on their agreements with MCE including: Community Energy Equity Resources LLC (CEER), Serious Controls LLC (SC), and Lawrence Berkeley National Laboratory (LBNL), (collectively “Grant Partners”). Approving the proposed Resolution 2025-04 would authorize the Chief Executive Officer (CEO) to negotiate and execute vendor agreements with the Grant Partners to continue the efforts under the Grant within the budget parameters as proposed to the CEC.

Background
Instead of being sited in one place like a physical power plant, a VPP harnesses energy resources that are distributed across a participating community. By coordinating these devices – like rooftop solar, heat pump water heaters, smart thermostats, smart plugs, electric vehicles, and batteries - VPPs can quickly supply power to the grid, take power from the grid, or lower energy consumption during critical times to reduce grid-strain. With enough grid-smart homes and businesses, a load serving entity like MCE can reduce costs and pass savings on to customers in the form of direct payment, credits, or reduced rates.

The VPP’s bidirectional power flow capabilities provide a unique ability to participate in the California Independent System Operator (CAISO) markets and capture value from those markets in a way previously unexplored by Community Choice Aggregators (CCA). MCE’s initial VPP pilot efforts were funded in part by the CEC’s Electric Program Investment Charge (EPIC) grant and were focused solely on serving sites within the City of Richmond, thereby ensuring that grid-smart technologies are accessible and actively deployed in low-income and historically underserved communities.

The VPP pilot phase included the creation of a customized Distributed Energy Resources Management System (DERMS) to communicate with, and dispatch power to and from, the installed grid-smart devices. This DERMS is the first of its kind, as it is custom-made for CCA operators. It leverages a first-of-its-kind VPP tariff which pays customers for the flexibility of these grid-smart, demand-flexible, devices. MCE then leveraged this experience to pursue additional funding opportunities to scale the VPP pilot phase from the City of Richmond to all of MCE’s service area. MCE’s proposal was then awarded the Grant.

Grant Partner Agreements
The Grant includes the Grant Partners listed above to implement key components of the Grant. The agreements with the Grant Partners are still in negotiation and not yet final. Any applicable obligations to MCE imposed by the CEC in the Grant agreement will pass through to the Grant Partners as terms and conditions in the agreements with the Grant Partners. Therefore, staff have prepared the anticipated terms below that would be included in each of the agreements with the Grant Partners for your Board to review.

It is anticipated that the agreements with the Grant Partners would include the following terms:
• Compliance with all applicable federal, state, and local laws. • Compliance with the terms and conditions of the Grant. • The agreement with CEER will have a not-to-exceed payment by MCE of up to $600,000. As part of their scope, CEER will provide services responsible for ensuring management of the workplan and efforts of other subcontractors, ensure a VPP toolkit is developed with customer settlement procedures, and ensure the DERMS platform is built out and tested for scale of customer use.
• The agreement with SC will have a not-to-exceed payment by MCE of up to $2,250,000. As part of their scope, SC will develop an updated DERMS platform that is Open ADR 3.0 certified, integrate the expanded VPP with California Independent System Operator (CAISO) markets so that MCE can bid into CAISO markets, and achieve load shifting through strategic deployment and optimization of installed devices.
• The agreement with LBNL will have a not-to-exceed payment by MCE of up to $600,000. As part of their scope, LBNL will provide analysis and value forecasting methodologies to assess the VPP value streams including revenues gainable by having the VPP participate in CAISO markets. LBNL services will help calculate the value distribution among participating customers and help inform incentive designs for participating and potential customers. • The agreements with the Grant Partners will have a term of 5 years. • Payments made to the Grant Partners under these agreements will be subject to the terms and conditions of the Grant ensuring that allowable expenses are captured and MCE receives applicable reimbursements under the Grant.

Fiscal Impacts:

The agreements with the Grant Partners will have a total not-to-exceed amount of $3,450,000 over a term of five years. The funds to pay the Grant Partners will be supported by funds received from the CEC under the Grant in addition to funds from MCE’s Operating Fund to satisfy MCE’s match fund requirement of the Grant. MCE’s match fund obligations applicable to Fiscal Year 2024/25 have been included in the Board-approved budget and funds spent in future fiscal years will be captured in applicable budgets.

Recommendation:

Approve proposed Resolution 2025-04 Authorizing the CEO to Negotiate and Execute Vendor Services Agreements with Community Energy and Equity Resources LLC, Serious Controls LLC, and Lawrence Berkeley National Laboratory for MCE’s Virtual Power Plant Program Supported by Funding from the California Energy Commission.

RESOLUTION 2025-04

A RESOLUTION OF THE BOARD OF DIRECTORS OF

MARIN CLEAN ENERGY AUTHORIZING THE CEO TO NEGOTIATE AND EXECUTE

VENDOR SERVICES AGREEMENTS WITH COMMUNITY ENERGY AND EQUITY

RESOURCES LLC, SERIOUS CONTROLS LLC, AND LAWRENCE BERKELEY NATIONAL LABORATORY FOR MCE’S VIRTUAL POWER PLANT PROGRAM

SUPPORTED BY FUNDING FROM THE CALIFORNIA ENERY COMMISSION WHEREAS, Marin Clean Energy (MCE) is a joint powers authority established on December 19, 2008, and organized under the Joint Exercise of Powers Act (Government Code Section 6500 et seq.); and
WHEREAS, MCE members include the following communities: the County of Marin, the County of Contra Costa, the County of Napa, the County of Solano, the City of American Canyon, the City of Belvedere, the City of Benicia, the City of Calistoga, the City of Concord, the Town of Corte Madera, the Town of Danville, the City of El Cerrito, the Town of Fairfax, the City of Fairfield, the City of Hercules, the City of Lafayette, the City of Larkspur, the City of Martinez, the City of Mill Valley, the Town of Moraga, the City of Napa, the City of Novato, the City of Oakley, the City of Pinole, the City of Pittsburg, the City of Pleasant Hill, the City of San Ramon, the City of Richmond, the Town of Ross, the Town of San Anselmo, the City of San Pablo, the City of San Rafael, the City of Sausalito, the City of St. Helena, the Town of Tiburon, the City of Vallejo, the City of Walnut Creek, and the Town of Yountville; and
WHEREAS, MCE and project partners submitted a project proposal to the California Energy Commission (“CEC”) to expand the Virtual Power Plant (VPP) pilot from the City of Richmond to all MCE member communities; and WHEREAS, the project partners submitted in the project proposal included Community Energy Equity Resources LLC (“CEER”), Serious Controls LLC (“SC”), and Lawrence Berkeley National Laboratory (“LBNL”), (collectively “Grant Partners”); and WHEREAS, MCE’s project proposal was approved by the CEC and MCE was awarded a grant in the amount for $5,000,000 (“MCE Awarded Funds”) with a required cost share by MCE in the amount of $5,000,000 (“MCE Match Funds”), for a project total of $10,000,000, to perform the work required to expand the Virtual Power Plant to all MCE member communities (“the Grant”); and
WHEREAS, In February 2025, your Board accepted the awarded Grant and authorized the CEO to enter into the Grant agreement with the CEC. Since your Board accepted the Grant, MCE desires to enter into agreements with the Grant Partners to continue the efforts under the Grant within the budget parameters as listed in the approved Grant;
NOW, THEREFORE, BE IT RESOLVED, by the MCE Board of Directors:

1. The Board of Directors finds that the aforementioned recitals are true and correct, and are herein incorporated into this Resolution.

2. CEO is hereby authorized to negotiate and execute Vendor Services Agreements with the Grant Partners, subject to approval by MCE’s General Counsel, for the provision of services to implement the Grant to scale the VPP pilot phase from the City of Richmond to all of MCE’s service area, which may include the following deal points:
• Compliance with all applicable federal, state, and local laws. • Compliance with the terms and conditions of the Grant. • The agreement with CEER will have a not-to-exceed payment by MCE of up to $600,000. As part of their scope, CEER will provide services responsible for ensuring management of the workplan and efforts of other subcontractors, ensure a VPP toolkit is developed with customer settlement procedures, and ensure the DERMS platform is built out and tested for scale of customer use.
• The agreement with SC will have a not-to-exceed payment by MCE of up to $2,250,000. As part of their scope, SC will develop an updated DERMS platform that is Open ADR 3.0 certified, integrate the expanded VPP with California Independent System Operator (CAISO) markets so that MCE can bid into CAISO markets for future revenue benefits, and achieve load shifting through strategic deployment and optimization of installed devices. • The agreement with LBNL will have a not-to-exceed payment by MCE of up to $600,000. As part of their scope, LBNL will provide analysis and value forecasting methodologies to assess the VPP value streams including revenues gainable by having the VPP participate in CAISO markets. LBNL services will help calculate the value distribution among participating customers and help inform incentive designs for participating and potential customers.
• The agreements with the Grant Partners will have a term of 5 years. • Payments made to the Grant Partners under these agreements will be subject to the terms and conditions of the Grant ensuring that allowable expenses are captured and MCE receives applicable reimbursements under the Grant.

PASSED AND ADOPTED at a regular meeting of the MCE Board of Directors on this 17th day of July, 2025, by the following vote:

CHAIR, MCE
Attest:
___________________________________________

SECRETARY, MCE
Customer
Operations
Overview
MCE Board of
Directors
July 17, 2025
Meet our Team!
2 Amy Allum-Poon
Customer
Operations
Manager
Ben Choi
Senior Account
Manager
Robert Grote
Manager of
Customer Service
Eddie Mercado
Customer
Success Advisor
II
Jazmin Nava Cid
Bilingual
Customer Success
Advisor II
Maria Echeverry
Bilingual Customer
Success Advisor
Coming in July
Customer
Operations
Analyst
Jared Sherwood
Senior Account
Analyst
What We Do
• MCE in-house, centralized service
center (1-stop shop)
• Billing Support and Management
• Program Management: Net Energy
Metering, Solar Billing Plan, Green
Access, Arrearage Management Plan,
Percentage of Income Payment Plan
• Relationship Management: PG&E &
SMUD (Billing Vendor)
• Customer data, reporting information,
and dashboards
• Salesforce CRM Development
Support 3
Service
Operations Billing
CO
MCE’s In-House Customer Service
4 Customer Success Advisors (CSAs) with 2
Bilingual (English and Spanish)
4 4 Customer Success Advisors
(CSAs) with 2 Bilingual (English
and Spanish)
Educate customers on value of
MCE and its offerings
Support Customer Programs with
customer service and customer
satisfaction-related projects
Answer all customer calls,
respond to voicemails, and
customer email inquiries
Billing
5 Billing agent
(PG&E)
relationship
management
Customer data &
cost comparisons
Solar Billing
Plan,Net Energy
Metering (NEM)
and Battery
Storage programs
Billing vendor
(SMUD)
management
New community
enrollments
Billing
operations &
billing expertise
Operations
6 Cross-departmental Coordination:

Communication, Processes and
Salesforce for Business Users
Identify opportunities to improve and
streamline internal processes
Process documentation & training for
CO Department
Manage MCE’s Green Access
(DAC-GT) and Solar Storage
Programs and Support Finance on
Accounts Receivables
Affordability Focuses
7 Green Access
● Bill savings for
highly impacted
disadvantaged
communities
MCE Cares Credit
● Monthly bill credit
for income-qualified and Small
Business customers
Arrearage
Management
Program (AMP)
● Eliminates up to
$8,000 of debt
Percentage of
Income Payment
Plan (PIPP)
● Caps customer
costs for gas and
electricity
Affordability Outcomes
8 Green Access
● Over $3M in bill
savings since 2021
(now ~5200
customers
enrolled)
MCE Cares Credit
● >28,000 residents/
800 Small Business
enrolled and
$5.5M distributed
Arrearage
Management
Program (AMP)
● 6,952 customers;
$4M of debt
enrolled
Percentage of
Income Payment
Plan (PIPP)
● $416,000 in
distributed savings
so far
Customer Communications
9 Call Trends
10 Top 3 Call Reasons
• Affordability/Opt
Actions
• Bill Questions
• Program Questions
Customer Retention
• 35% Retained
• 3,910 Retained since
Call Center launch
• 810 Retained in 2025
Call Language
• 22% of all
calls serviced
in Spanish
MCE Participation Trends
11 Contacting Customer Operations
12 Single Point of Contact for all inquiries
• Call us Monday - Friday 9am - 5pm at (888) 632-3674
• Email us anytime at [email protected]
12 mceCleanEnergy.org
[email protected]
Thank you!
July 17, 2025
TO: MCE Board of Directors
FROM: Jackie Nuñez, Senior Communications Manager
RE: Language Accessibility Study Report
ATTACHMENT: Enhancing Language Accessibility
Dear Board Members:

Summary:

As part of an initiative to build trust and enhance language accessibility to non-English speaking customers, MCE conducted a study to understand the best communication channels and approaches for engaging with people who experience language barriers.

Background
In 2023, MCE formed an internal working group among various departments to build on the agency’s existing language accessibility efforts and identify the most effective ways to serve non-English speaking customers. That year, nearly one in three calls to MCE’s service center were received in Spanish. This prompted MCE to better understand community language needs and identify approaches to providing excellent service to this population.

The working group:
• Assessed community language demographics and processes for serving individuals proficient in languages other than English
• Met with other Community Choice Aggregators and public agencies to share best practices • Developed internal guidelines to operationalize language accessibility procedures This initiative revealed that:
• Spanish is the most prevalent language among non-English speakers in MCE’s area, followed by Tagalog and Chinese
• Roughly 8% of households in MCE’s service area are linguistically isolated, meaning members of the family above the age of 14 do not speak English proficiently In response to these findings, MCE hired a local vendor, Soluna Outreach Solutions, to conduct a language study. The study aimed to understand community priorities, identify the best communication channels to reach individuals, and find the most culturally appropriate terminology to engage with communities around clean energy and climate change.

Soluna Outreach Solutions conducted focus groups in Spanish, one in each county across MCE’s service area in partnership with the following local community-based organizations (CBOs). • Latina Center, Contra Costa County
• Multicultural Center of Marin, Marin County
• Puertas Abiertas, Napa County
• First Five, Solano County
The study found:
• There is an opportunity to build trust with the community around electricity service and clean energy, providing clearer and less technical communications in various formats ranging from written communications and video
• People are interested in in-person conversations and learning opportunities about how to lower bills
• Customers prefer email and physical mail for detailed information and text messages for urgent notices
• Working with local partners, including nonprofits and CBOs, is an effective strategy to build trust especially with non-English speaking communities
MCE has used the results of the study to inform its communications, community engagement, and customer service strategies to establish excellence in service to people facing language barriers.

Staff will continue to assess best practices and identify opportunities to work toward an inclusive and equitable approach to serving non-English speaking customers.

Fiscal Impacts: All contractual and staff costs are within the approved fiscal year budget.

Recommendation: Discussion only.

MCE
Language Accessibility
Study Report
Enhancing
Language Access
• 24% of MCE’s inbound calls were
in Spanish in 2024
• More than 8% of households are
linguistically isolated
• Spanish is the most prevalent
language among non-English
speakers in our area, followed by
Tagalog and Chinese
2 Supports those most
impacted by our
changing climate.

Our Efforts
• Assessed demographics and
processes
• Met with other CCAs and public
agencies to share best practices
• Developed language guidelines
• Conducted a language study
• Trained and hired 5 bilingual staff
3 Language Study
• Understand language and
communication channels preferred
by Spanish speakers
• One focus group in each county,
total of 24 participants
• Hosted with local partners to build
trust
• Diverse participants of various ages,
including MCE customers and non-customers
4 “We need more culturally-sensitive outreach that helps people learn about MCE
through trusted community
sources.”
— Community Power
Coalition member
5 Findings
• An opportunity to build trust around electricity
service and clean energy
• Interest in in-person conversations, learning
opportunities
• Customers prefer email and physical mail for
detailed information
• Text message for urgent notices
• Continue collaborations with local partners to
build trust
• Topics of interest
• How to lower bills
• More clarity about billing and rates
• Financial assistance programs
Terminology
exercise
Next Steps • Use findings to inform MCE’s public
engagement and communications
• Discussion with ComPow in July • Continue to refine internal practices to support non-English speakers
• Explore other community
accessibility needs including for
people with disabilities, technology
and other barriers
6 mceCleanEnergy.org
[email protected]
Thank you!
Marketing & Communications
Quarterly Executive Report
April – June 2025
Q2 CY2025
1 Marketing
Summary
602,385
emails sent
40 email campaigns 2
ad campaigns
129,276
mailers sent
13 mail campaigns 5
new flyers & webpages
2 3
• Won a Bronze SF ADDY Award in the Best
Public Service TV category for MCE’s "Unplugged" 4-9 video campaign • Hercules Enrollment and Brand Awareness Ad
Campaigns: over-delivered on campaign
impressions and learned that radio is highly
effective channel to reach Spanish speakers
• Nicole Busto, Director of Marketing, presented
MCE’s rebranding and website refresh at the
CalCCA Conference Marketing session
• Madeline Sarvey begins new role as Marketing
Coordinator
• Team welcomes Marketing Intern, Maddie Chiu • Allen Chiu, Senior Digital Marketing Manager and Nicole Busto achieve 10-year MCE
anniversary
Team Highlights
3 Service
Area-wide Ad
Campaign Hercules, MCE’s newest member community
5 4-9 Load Shifting Campaign
Messaging
• “Save money when using appliances.”
“Supercharge your savings before 4 p.m.”
Ad placements
• Out-of-home (30 EV charging stations,
1 digital billboard), social ads in English
and Spanish (static, animated and
4 user-generated content videos): 5M+
estimated impressions
Timeframe
June 23 – September 14, 2025
Team
• Lead: Heather; Vendor: Most Likely To
5 Special Projects
7 Anniversary
Branding
Materials created
• Zoom backgrounds
• Staff email signatures
• Slide deck template
Team
• Leads: Spike, Heather
Targeted
Marketing
Campaigns Marina Bay Northshore residents enjoy their
recently installed EV chargers
Arrearage
Management Plan
Enrollment Campaign
Details TK
Target customers: Enrolled in California Alternate
Rates for Energy or Family Electric Rate Assistance,
owes at least $500 with bills over 90 days past due,
and have made at least one on-time payment
Message: Get up to $8,000 in debt forgiveness
Call to action: Apply on PG&E’s website
Campaign + materials created:
• Email - 8,610 sent
• Mailer - 292 sent
Program goal: 50% participation rate
Performance to date: 997 enrolled
Team: Leads: Kalicia, Allen 9
Email
enrollment
was 4 times
the typical rate
(12% vs. 3%)
Deep Green Fairfax
Credit
Target customers: Residential Fairfax customers
without solar
Message: Receive a $5 bill credit for 100%
renewable energy
Call to action: Enroll in Deep Green
Campaign + materials created:
• Co-branded email with simplified checkbox
form – 3,373 sent
• Webpage
• Flyers for Fairfax events with QR code
Program goal: 100 customers
Performance to date: 92 forms submitted;
88 submissions approved
Team: Leads: Nicole, Allen 10
Enrolled 72%
of goal with first
marketing
email
Energy Management
Benicia Co-branded Campaign
Target customers: Benicia commercial
customers
Message: Receive equipment upgrades and
rebates through MCE’s Energy Management
programs
Call to action: Scan QR to learn more
Campaign + materials created:
• Mailer – 93 mailed
Team: Lead: Jayne
11 Co-branded
with the
City of Benicia!
Hercules Enrollment
Target customers: Hercules residents and businesses
Message: MCE will be your new electricity provider
starting in April
Call to action: Visit or contact us to learn more
Campaign + materials created:
• General customers:
• Notice 2: 2,362 English and Spanish emails; 303
bilingual mailers
• Notice 3 + 4: 12,186 English and Spanish emails;
2,175 bilingual mailers
• Solar customers:
• Notice 1 + 2: 862 bilingual mailers sent
• Notice 3 + 4: 690 bilingual mailers sent
• Workshop invitations and post-event emails
• Ads: social, digital, bus bench February to May
• Flyers: English; Spanish; Commercial
• Webpage
Team: Lead: Nicole; Support: Spike, Allen, Sarah 12
MCE Sync
EV Charging App
Target customers: EV drivers in a state-designated
priority population within MCE’s service area
Message: Save up to $220 annually on your EV
charging
Call to action: Download the MCE Sync app
Campaign + materials created:
• Mailer - 7,442 sent
Program goal: 5,000 participants by Q1 2026
Performance to date: 33 downloads, 21 accounts
created
Team: Lead: ev.energy; Support: Kalicia
13 MCE Sync
EV Charger Rebate
Target customers: EV drivers who live in a state-designated priority population within MCE’s service area and received MCE’s EV Instant Rebate
Message: Get up to $600 off an EV charger
Call to action: Buy an MCE Sync-compatible EV
charger and apply for the rebate
Campaign + materials created:
• Email - 1,172 sent
Program goal: Provide 100 home charger rebates
by Q1 2026
Performance to date: 6 rebates issued
Team: Lead: ev.energy; Support: Kalicia
14 Peak Flex Market
2025 Season
Target customers: Non-residential customers
Message: Get paid to shift your energy usage
Call to action: Submit interest form
Campaign + materials created:
• Email – 604 sent
• Mailer – 308 mailed
Program goal: 13 forms submissions based on
1% campaign conversion rate
Performance to date: 9 form submissions
Team: Lead: Jayne
15 Embedded and
simplified form
makes it easier
to show
interest!
2025 RFI for
Long-Term Offers
Target customers: Energy supply project
developers and trade organizations
Message: Notice of MCE’s 2025 Request for
Information for Long-Term Offers
Call to action: Submit Request for Information
Questionnaire
Campaign + materials created:
• Request for Information Questionnaire
• Save-the-Date Email – 423 sent
• Request for Information Launch Email – 427 sent
• Reminder Emails (2 rounds) – 862 sent
Program goal: Test alternative Open Season
procedure to streamline process for participants and
Power Resources staff
Performance to date: 113 project offer submissions
Team: Lead: Sarah; Support: Allen 16
New streamlined
MCE-administered
questionnaire to
simplify
submission
process
Small Business
Energy Advantage
Vallejo Campaign
Target customers: Vallejo small businesses
Message: Free energy assessments and upgrades
for small businesses in Vallejo
Call to action: Submit interest form
Campaign + materials created:
• Email – 604 sent
• Mailer – 308 mailed
Program goal: 3 community engagement events
Performance to date: 10 pre-event form
submissions (2.4%), 3 post-event form submissions
(1.5%), 26 Vallejo businesses enrolled
Team: Lead: Jayne 17
Co-branded
with the City of
Vallejo!
18 • Community Power Coalition Event
• March post-event email
• May invitation, reminder, and post-event
emails
• Certify & Amplify 2025 Event
• Small Business Energy Advantage invitation
email
• New webpages
• EV rebate dealership enrollment – 86 form
submissions from organic traffic
• New flyers:
• MCE contractor programs
• Co-branded Commercial Flex Market
program
• Team: Leads: Sarah, Kalicia, Jayne; Support:

Nicole, Ayaka
Additional Support
MCE’s Small Business Energy Advantage program staff
getting the word out to Vallejo businesses
Ongoing Notices
Green Access Move-Out
262 emails sent
Team
• Lead: Allen, Spike (New Move-in; Deep Green Welcome)
• Support: Kalicia (Green Access)
New Move-In
39,741 emails + 29,287 mailers sent
19 Deep Green Welcome
285 emails sent
Communications
Green Workforce Pathways promotes
workforce development curriculums
21 • Green Leadership in Action: MCE Recognizes Bay
Area Changemakers– 789 emails sent
• MCE Celebrates 15 Years as California’s First
Community Choice Energy Provider
– 791 emails
sent
• MCE and Calpine Add More Renewable, Reliable
Power from The Geysers, the World’s Largest
Geothermal Complex
– 1,042 emails sent
• Bay Area Residents to Save $65 Million With MCE’s
Clean Energy Projects
– 1,014 emails sent
• Newsletters – 17,449 emails sent
• Top ranked content: April
– McGlashan
Award (32 page visits); May
– 4 to 9 tips (51
page visits); June– Calpine (57 page visits)
• Team: Lead: Jackie; Support: Madeline, Sarah
Press Releases +
Newsletters
22 • Volts podcast interview with Dawn: The Past
and Future of CCAs
• San Francisco Chronicle CEOs share how to
build trust, a positive culture
• San Francisco Business Times Most Influential
Women in Bay Area Business Feature on Dawn
• KQED The Bay Podcast - Can 'Virtual Power
Plant' Technology Help Our Power Grid?
• Edible Marin & Wine Country Fallon Two Rock
Feature
• The EV Report Dynamic Pricing Optimizes
California EV Charging
• Richmond Standard Deal brings 24/7
geothermal energy to local homes, businesses
• Team: Lead: Jared, Jackie Support: Shyna
Earned Media
23 • City of Martinez Goes 100% Renewable • An Inside Look at MCE’s Power Resources Team with Stephen Mariani
• The Power of Partnerships: How MCE
Strengthens Communities
• Youth Take the Lead at Our First-Ever
Because of Youth Festival
• 4 Ways Your Business Can Beat Summer’s
Peak Energy Costs
• Renters: How to Save Energy during 4-9
• Team: Lead: Shyna, Madeline
Blog Posts
24 • Reached 8,000 LinkedIn followers, 16%
increase year over year
• Awards • San Francisco Business Times Most
Influential Women in Business Award gala
for Dawn
• San Francisco Chronicle Top Workplace
award
• Sponsorships: • Pacific Offshore Wind Summit • RISE Climate & Wine Symposium • CA Energy Demand Management Council Spring Symposium
• Team: Leads: Jackie, Shyna
Other Updates
mceCleanEnergy.org
[email protected]
Thank you!
July 17, 2025
TO: MCE Board of Directors
FROM: Sabrinna Soldavini, Director of Policy
RE: Policy Update of Legislative and Regulatory Items
ATTACHMENT: Regulatory Packet with Filings since the April Board Meeting Dear Board Members:

Below is a summary of the key activities at the state and federal legislatures and the California Public Utilities Commission (CPUC), California Energy Commission (CEC), and the California Independent System Operator (CAISO) impacting Community Choice Aggregation (CCA) and MCE.

I. Legislative Advocacy
a. California
By the time of this board meeting, all remaining active bills will have been heard in second house policy committees unless a rule waiver has been negotiated. As usual, many large and/or controversial issues will be granted exceptions to bypass the normal process and be addressed in the weeks just before the end of session on September 12th. Staff expect that among energy and climate issues, regional markets, electric affordability, and cap and trade reauthorization are likely to be included in the late summer sprint to the finish. As was the case last year, the state budget deficit as well as the forecasts of future deficits are providing context for policy bills under consideration, as there is little to no money the state can spend on new or expanded initiatives.

Since the last staff report, MCE has registered an Oppose Unless Amended position on AB 825 (Petrie-Norris). While the bill contains several provisions designed to deliver meaningful affordability benefits to electric customers by reducing transmission and distribution costs, it contains a section that would infringe upon CCA autonomy and the authority of our governing boards to make decisions about the programs CCAs offer our customers. We continue to work transparently and productively with the author’s staff to discuss our concerns and are hopeful that they can be addressed through future amendments.

The below table lists the positions MCE has registered to date.

Bill Number and
Author
Subject MCE Position
SB 540 (Becker,
Stern)
Pathways Initiative, regional energy
markets
Support
SB 330 (Padilla) Alternative financing for transmission Support SB 302 (Padilla) Renewable tax conformity Support
AB 443 (Bennett) Green hydrogen, curtailed renewables Support SB 326 (Becker) Wildfire mitigation strategic planning Support AB 1280 (Garcia) IBank Climate Catalyst funding eligibility for industrial decarbonization projects
Support
AB 806 (Connolly) Supporting installation of cooling units in mobile homes
Support
SB 541 (Becker) Load-shifting and rates requirements Oppose Unless Amended
AB 825 (Petrie-Norris)Electric affordability (multiple topics) Oppose Unless Amended
b. Federal
H.R. 1,
1 the federal budget reconciliation omnibus bill, was signed into law on July 4th. Among other provisions, the bill contains the following significant changes to the Inflation Reduction Act’s (IRA) clean energy tax credits. MCE staff are still analyzing the impacts of these changes on our procurement, programs, and agency costs, and will have more information to share as the implications of these changes become more clear.

Over the last several months, MCE joined the chorus of clean energy advocates and other impacted stakeholders lobbying against these changes, and will continue to work with these coalitions as the effects of this significant legislation begin to take shape.

Credits for commercial renewables
H.R. 1 significantly accelerates the sunset dates for the Investment Tax Credit and Production Tax Credit for solar and wind projects. Projects must start construction before July 4, 2026 in order to be eligible for existing tax credits, assuming all other eligibility criteria have been met.

Projects that start construction after July 4, 2026 must come online before Dec. 31, 2027 in order to be eligible for credits. Credits for these technologies do not phase out gradually.

For all other technologies, including batteries, geothermal, hydroelectric, and nuclear, projects must begin construction by Dec. 31, 2033 in order to be eligible for the full tax credit. After 2033, the credit ramps down annually until it is fully eliminated for projects that start construction in or after 2036.

H.R. 1 also imposes a set of complex new restrictions on “foreign entities of concern” (FEOC).

Broadly speaking, prohibited foreign entities (as defined in the bill) cannot receive these tax credits. Additionally, projects that use more than a specified percentage of components, calculated by cost, that are sourced from a prohibited foreign entity are ineligible to receive the credits.

Credits for individual customers
H.R. 1 accelerates the sunset of the IRA’s customer-facing tax credits as well. These changes will not impact MCE’s agency finances but will make clean energy investments more expensive for our customers. Customers will still have access to incentives funded either by MCE or by state sources, but will be unable to stack federal incentives after the following dates:
• Previously-owned Clean Vehicle Credit (25E) ends for vehicles acquired after Sept. 30, 2025
• Clean Vehicle Credit (30D) (new vehicles) ends for vehicles acquired after Sept. 30, 2025
• Commercial Clean Vehicle Credit (45W) ends for vehicles acquired after Sept. 30, 2025 • Alternative Fuel Vehicle Refueling Property Credit (30C) ends for property placed in service after June 30, 2026
1 H.R. stands for House of Representatives, where the bill was originally introduced. • Energy Efficient Home Improvement Credit (25C) ends for property placed in service after Dec. 31, 2025
• Residential Clean Energy Credit (solar, batteries, etc.) (25D) ends for expenditures made after Dec. 31, 2025 (for systems owned by the customer/taxpayer) • Credits end for solar systems leased to residential customers after Dec. 31, 2027 • Energy Efficient Commercial Buildings Deduction (179D) ends for property on which construction starts after June 30, 2026
• New Energy Efficient Home Credit (45L) ends for homes acquired after June 30, 2026 MCE-specific funding
While MCE has a small number of federal grants from different programs, staff are not aware of any impacts resulting from H.R. 1.

II. California Public Utilities Commission (CPUC)
a. Power Charge Indifference Adjustment (PCIA) Proceeding In February 2025, the CPUC issued an Order Instituting Rulemaking (OIR) to update Energy Resource Recovery Account (ERRA) and Power Charge Indifference Adjustment (PCIA) policies and processes. Per law, the CPUC is required to ensure “indifference” and prevent cost shifts between bundled and unbundled customers. This entails the Investor-Owned Utilities (IOUs), such as Pacific Gas & Electric (PG&E) recovering electricity costs from CCA customers that were incurred on their behalf before they departed PG&E service, and reducing those costs by the value of benefits that remain with PG&E customers. To facilitate this process, the Commission established the PCIA, a charge paid by all customers on the PG&E side of the bill.

In this proceeding, the CPUC is evaluating potential changes to the methodology of calculating the PCIA through two tracks. Track 1 considered interim changes to the calculation of the Resource adequacy (RA) Market Price Benchmark (MPB), one of the inputs used to calculate the PCIA, on an expedited basis. Track 2 will consider broader, long term changes to the overall PCIA methodology and will begin in 2026.

The CPUC issued a Proposed Decision (PD) in Track 1 of the proceeding in May 2025 approving the RA MPB methodology changes and allowing the IOUs’ to apply these changes retroactively to previously approved rates. CalCCA filed opening and reply comments on the PD reiterating our position of preserving accuracy, transparency and fairness in calculating the RA MPB. The comments highlighted the absence of substantial evidence throughout the process of reaching the decision and the lack of legal analysis to support application of a new methodology to previously approved rates. The CPUC voted to finalize the PD with no major changes on June 26, 2025.

MCE will continue to actively engage in this proceeding through 2025 and provide updates as they become available.

Fiscal Impacts: There are no immediate fiscal impacts to MCE, but changes to the methodology will impact the PCIA charge paid by MCE customers for 2026 and beyond and are expected to increase PCIA rates for MCE customers. MCE Staff will continue to provide updates on expected PCIA rates for 2026 as we approach January 2026. b. PG&E Billing Modernization Initiative
In October 2024, PG&E submitted an Application for approval to recover 2023-2030 revenue requirements ($761.3 million) for its Billing Modernization Initiative (BMI). BMI will replace PG&E’s aging billing system currently used to serve its electric and gas customers, including MCE customers, as PG&E serves as the billing agent for MCE, in the areas of billing, customer service, and customer data management. PG&E proposes to recover the costs of these upgrades from all customers, bundled and unbundled.

MCE is working with a group of Joint CCAs in PG&E’s service territory and in June 2025, the Joint CCA group filed Intervenor Testimony advocating for billing systems and processes that result from this upgrade to be: 1) sufficient to meet CCA customer needs and 2) designed to equitably serve both PG&E’s bundled and unbundled (CCA) customers. The Joint CCAs stated the need for the costs of this upgrade to be fairly allocated and urged the CPUC to ensure that PG&E’s billing system and cost allocation proposals do not confer an unfair competitive advantage to PG&E.

MCE will continue to work with the Joint CCA group in this case and engage with PG&E throughout the BMI upgrade process.

Fiscal Impacts: There are no immediate fiscal impacts to MCE, but costs from the upgrade will impact the distribution charge paid by MCE customers in the future. c. Provider of Last Resort (POLR) Phase II
MCE is currently engaging in Phase 2 of the POLR proceeding with the California Community Choice Association (CalCCA) to implement relevant provisions of SB 520 (2019). SB 520 required the CPUC to determine the requirements and regulatory framework for a POLR (the entity required to serve customers if a Load Serving Entity (LSE) can no longer serve their customers and designated the IOUs as the POLRs for their respective service areas. The CPUC is also required to determine the conditions and process for the transfer of POLR responsibilities from an IOU to a non-IOU LSE, including a CCA.

In May 2025, the CPUC issued a ruling seeking responses to (1) the CPUC’s authority over a non-IOU POLR; and (2) a potential procedural path to consider any future applications for POLR status by a non-IOU LSE. In June 2025, CalCCA filed Opening and Reply Comments in response to the ruling. CalCCA advocated that the CPUC’s authority over a non-IOU POLR is limited to only the provision of POLR service, and does not extend beyond those services to any other operations. CalCCA supported the CPUC’s proposal to issue an interim decision that provides a framework for its regulatory authority over a non-IOU POLR and the services it provides. Further details on the transfer of POLR responsibilities will be finalized if and when a non-IOU entity demonstrates interest in assuming POLR status.

MCE will continue to work with CalCCA to ensure that reasonable terms are established for any CCAs interested in assuming POLR responsibilities in the future.

Fiscal Impacts: There is no direct fiscal impact to MCE at this time. d. Disconnections
In May 2025, the CPUC issued a PD addressing reconnection and extreme heat protections in the Disconnections proceeding. The PD requires the IOUs to reconnect customers who have been disconnected for the first-time with no conditions beyond enrolling the customer in a payment plan. Following that first-time disconnection, customers will be protected from disconnection for three months. The PD also requires the IOUs file proposals for heat-based disconnection thresholds within six months and to adopt them by May 1, 2026.

CalCCA filed opening comments recommending that the CPUC approve the PD’s reconnection framework. CalCCA also recommended that the CPUC require the IOUs to include a breakdown of unbundled customers in monthly disconnection reports, and to provide regular reports to CCAs regarding customers at risk of disconnection. The CPUC adopted a Final Decision at the June 12, 2025, Voting Meeting, and declined to adopt CalCCA’s recommendations.

Fiscal Impacts: There are no direct fiscal impacts to MCE at this time. e. Distributed Energy Resources Data Working Group
In May 2025, the CPUC’s Data Working Group held its final meeting. CalCCA and MCE have been participating in the working group series since August 2024. At the final meeting, the working group facilitators invited stakeholders to submit informal comments on the data use cases compiled during the course of the working group. On June 13, 2025, CalCCA submitted informal comments recommending 1) that CCA data use cases be prioritized due to the large number of CCA customers and the longstanding nature of ongoing data needs, and 2) that the primary outcome of the working group be an action plan including an implementation timeline and a prioritized list of data use cases. A draft of the working group report will be published by the facilitators and made available for comment in Fall 2025.

Fiscal Impacts: There are no direct fiscal impacts to MCE at this time. f. Resource Adequacy (RA)
In June 2025, the CPUC adopted a Final Decision in Track 3 of the RA proceeding. Track 3 considered a number of near-term changes to the RA program including: adoption of an updated Planning Reserve Margin (PRM) for 2026 and 2027 (the PRM is the additional amount of RA-eligible capacity above base RA requirements to ensure sufficient capacity is available for grid operations under stressed conditions); compliance methodology modifications to account for the RA program’s transition to the Slice-of-Day (SOD) framework; and whether to adopt and implement a System RA waiver process whereby a Load Serving Entity (LSE) would be able to seek a penalty waiver for a portion of its RA requirements provided the LSE demonstrated it took sufficient commercial action to meet those requirements.

The Final Decision increased the PRM for 2026 and 2027 to 18 percent (from the current 17 percent), which represents a more modest increase than the CPUC originally contemplated.

The Final Decision, however, also continued the effective PRM for the IOUs, which authorizes the IOUs to procure additional RA capacity beyond the PRM from June to October as an additional capacity buffer during the high demand summer months.

The Final Decision declined to adopt RA waiver proposals, which were intended to help balance reliability and affordability and mitigate cost impacts of the anticipated PRM increase.

The Final Decision also declined to adopt CalCCA’s proposed enhancements to the RA framework that would allow LSEs to trade hourly load obligations - a proposal that would incentivize LSEs to optimize their SOD portfolios and bring cost savings to the RA program.

The Final Decision, however, directed CPUC Staff to continue to assess the feasibility and need for load obligation trading and potentially adopt the proposal in a future stage of the proceeding.

Fiscal Impacts: While the exact impact is undetermined, the PRM increase will impact procurement costs as the PRM affects the amount of RA MCE will be required to purchase to meet its compliance needs and support reliability.
g. Disadvantaged Communities Green Tariff (DAC-GT)
Through the CPUC’s Disadvantaged Communities Green Tariff (DAC-GT), MCE offers the Green Access Program, which provides low-income MCE customers living in pollution burdened communities with a 20% discount on their electricity bill, and 100% solar energy from a project located in a pollution burdened community.

In May 2024, the CPUC adopted D.24-05-065 which ordered PG&E and Southern California Edison Company (SCE) to work with participating CCAs to develop a proposal for updating the cost containment cap applicable to the DAC-GT program. The cost cap is a key factor in determining which renewable projects are eligible for participation in the program. In August 2024, the Joint IOUs proposed a methodology to reduce the cost cap that renders the DAC-GT program unworkable for many program administrators. In May 2025, the CPUC issued a Draft Resolution adopting the Joint IOUs’ methodology.

MCE worked with a group of CCAs that filed comments on the Draft Resolution. The Joint CCAs reiterated their interest in operating a successful DAC-GT program and highlighted the shortcomings of the methodology. The Joint CCAs also proposed reasonable alternatives that could be implemented in case no bids are received under the cost cap.

MCE is awaiting a decision on a Final Resolution and will share updates as they become available.

Fiscal Impacts: There is no direct fiscal impact to MCE at this time, but a reduced cost cap may impact MCE’s ability to procure new projects to serve the DAC-GT program. MCE will provide updates on future DAC-GT solicitations when they become available. h. Energy Efficiency (EE)
In June 2025, MCE submitted opening and reply comments on the proposed scope of the CPUC’s new order instituting a rulemaking on EE policies and portfolios. MCE’s comments supported the proposed scope’s discussion of oversight of EE programs generally and for program years 2024-2027, advancing decarbonization through EE programs, and policy guidance for 2026 EE applications.

MCE also supported adding a discussion of the CPUC’s Environmental and Social Justice Action Plan, non-energy benefits, energy affordability and the California Energy Efficiency Coordinating Committee to the proposed scope of the proceeding. MCE participated in a Prehearing Conference on the proposed scope and schedule of the proceeding offering similar comments in June 2025. MCE anticipates a scoping ruling from the Commission this summer.

In June 2025, MCE also received a disposition letter approving the Joint EE Program Administrator submitted advice letter on EE program overlap, mitigation activities and assessing any corresponding financial risks to ratepayers. MCE and other program administrators jointly prepared and submitted this advice letter in October 2024. In its June disposition the CPUC agreed with jointly submitted program administrator analysis that existing mechanisms to prevent and mitigate any financial risk from overlapping EE programs are very effective reducing the risk to less than 0.08% of annual EE funding.

Fiscal Impacts: There is no direct fiscal impact to MCE at this time.

III. California Independent System Operator (CAISO)
a. Demand and Distributed Energy Market Integration
The CAISO’s Demand and Distributed Energy Market Integration (DDEMI) working group held two meetings in April-May 2025 to discuss problem statements for performance evaluation methodologies, which are generally used to create an estimated baseline of expected use had there not been a Demand Response event.

MCE participated in both meetings and submitted written comments on May 1 and May 27, 2025. MCE’s comments recommended that the working group move forward with the problem statements focused on improvements to the control group methodology. MCE also recommended that the working group deprioritize the problem statements that included a narrow focus on device-level measurement and registration. On June 13, 2025, the CAISO issued an updated discussion paper incorporating some of MCE’s recommendations. MCE will continue to participate in the working group.

Fiscal Impacts: There are no immediate fiscal impacts to MCE.

MCE Board of DirectorsJuly 17, 2025

MCE Board of Directors
July 17, 2025