Agenda packet — WestLight Energy Board of Directors, April 24, 2025 (part 1 of 2)

2075 Woodside Road | Redwood City, CA 94061
(650) 260-0005 | peninsulacleanenergy.com
Regular Meeting of the Board of Directors of the
Peninsula Clean Energy Authority (PCEA)
AGENDA
Thursday, April 24, 2025
6:30 pm
PLEASE NOTE: This meeting will be held in a hybrid format with both in-person and Zoom participation options for members of the public;
Board members shall appear in person.

In-Person Meeting Locations:

PCEA Lobby, 2075 Woodside Road, Redwood City, CA 94061
Los Banos City Hall, Conference Room A, 520 J Street, Los Banos, CA 93635 Hyatt Regency Sacramento 1209 L Street, Sacramento, CA, US, 95814 Zoom, Virtual Meeting Link: https://pencleanenergy.zoom.us/j/87496649657 Meeting ID: 874-9664-9657 Passcode: 2075 Phone: +1 (669) 444-9171 Introduction
This meeting of the Board of Directors will be held at the Peninsula Clean Energy Lobby: 2075 Woodside Road, Redwood City, CA 94061 and Los Banos City Hall, Conference Room A, 520 J Street, Los Banos, CA 93635 and by teleconference pursuant to California Assembly Bill 2449 and the Ralph M. Brown Act, CA Gov’t Code. Section 54950, et seq. Members of the Board are expected to attend the meeting in person and should reach out to General Counsel for Peninsula Clean Energy, Jennifer Stalzer, with questions or accommodation information ([email protected]). For information regarding how to participate in the meeting remotely, please refer to the instructions at the end of the agenda. In addition, a video broadcast of the meeting can be viewed at https://www.peninsulacleanenergy.com/board-of-directors following the meeting.

Public Participation
The PCEA Board meeting may be accessed through Zoom online at https://pencleanenergy.zoom.us/j/87496649657. The webinar ID is: 874-9664-9657 and the passcode is 2075. The meeting may also be accessed via telephone by dialing +1(669) 444-9171. Enter the webinar ID: 874-9664-9657, then press #. (Find your local number:
https://pencleanenergy.zoom.us/u/kTlH1Ocod). Peninsula Clean Energy uses best efforts to ensure audio and visual clarity and connectivity. However, it cannot guarantee the connection quality.

Members of the public can also attend this meeting physically at the Peninsula Clean Energy Lobby at 2075 Woodside Road, Redwood City, CA 94061 or Los Banos City Hall, Conference Room A, 520 J Street, Los Banos, CA 93635.

Written public comments may be emailed to PCEA Board Clerk, Nelly Wogberg ([email protected]) and such written comments should indicate the specific agenda item on which the member of the public is commenting.

Spoken public comments will be accepted during the meeting in the Board Room(s) or remotely through Zoom at the option of the speaker. Please use the “Raise Your Hand” function in the Zoom platform, or press *6 if you phoned into the meeting, to indicate that you would like to provide comment. 1 1. Approval of Revised Load Management Standard (LMS) Plan for Submission to California Energy Commission (CEC)

2. Approval of Minutes from the March 27, 2025 Board of Directors Meeting

3. Chair Report (Discussion)

4. CEO Report (Discussion)

5. Community Advisory Committee Report (Discussion)

6. Briefing on SB 540 (Becker) - Western Pathways Bill (Discussion)

7. Approval of the Program Plan for California Public Utilities Commission (CPUC) FLEXmarket Program (Action)

8. Discussion of the Distributed Energy Resources Framework 2025 - 2030 (Discussion)

9. Approval of the Budget Billing Program for Peninsula Clean Energy Customers (Action)

10. Board Members’ Reports (Discussion)
Please note that Peninsula Clean Energy Board of Directors meetings are a limited public forum, and all public comment must relate to something that is within the subject matter jurisdiction of the Board. If comments do not relate to the subject matter jurisdiction of the Board, we will stop the comment and move on to the next speaker. General Counsel will assist in identifying comments that are not related to the subject matter jurisdiction of the Board.

ADA Requests
Individuals who require special assistance or a disability related modification or accommodation to participate in this meeting, or who have a disability and wish to request an alternative format for the meeting, should contact Nelly Wogberg, Board Clerk, by 10:00 a.m. on the day before the meeting at ([email protected]). Notification in advance of the meeting will enable PCEA to make reasonable arrangements to ensure accessibility to this meeting, the materials related to it, and your ability to comment.

Closed Captioning is available for all PCEA Board meetings. While watching the video broadcast in Zoom, please enable captioning.

CALL TO ORDER / ROLL CALL / APPROVE TELECONFERENCE PARTICIPATION UNDER AB 2449
This item is reserved to approve teleconference participation request for this meeting by Director pursuant to Brown Act revisions of AB 2449 due to an emergency circumstance to be briefly described.

PUBLIC COMMENT
This item is reserved for persons wishing to address the Board on any PCEA-related matters that are not otherwise on this meeting agenda. Public comments on matters listed on the agenda shall be heard at the time the matter is called. Members of the public who wish to address the Committee are customarily limited to two minutes per speaker. The Board Chair may increase or decrease the time allotted to each speaker.

ACTION TO SET AGENDA AND TO APPROVE CONSENT AGENDA ITEMS

REGULAR AGENDA
2 11. Community Energy Programs Quarterly Report

12. Marketing, Outreach Activities, and Media Relations Quarterly Report

13. Legislative Update

14. Report on California Community Power (CCP) Joint Powers Authority

15. Social Media FAQ's

16. Acronym List

INFORMATIONAL REPORTS

ADJOURNMENT
Public records that relate to any item on the open session agenda are available for public inspection. The records are available at the Peninsula Clean Energy offices or on PCEA Website at:
https://www.peninsulacleanenergy.com.

JOINING INSTRUCTIONS
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You will be instructed to enter the meeting passcode 2075 followed by #. 5 DATE: April 16, 2025
MEETING DATE: April 24, 2025
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Jeremy Waen, Senior Director of Regulatory Policy SUBJECT: Approval of Revised Load Management Standard (LMS) Plan for Submission to California Energy Commission (CEC)
Item No. 1

PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence

BACKGROUND
Pursuant to 20 Cal. Code Regs. §1623.1, the California Energy Commission ("CEC") requires Community Choice Aggregators (CCA) to develop and approve a Load Management Standard ("LMS") plan for the real-time management of customer load. This load management aims to reduce load at peak and to reduce overall costs. The California Energy Commission’s regulation relies primarily on the creation of “marginal cost-based" (MCB) hourly rates as the tool to shift customer load out of expensive-to-serve hours. As an alternative, CCAs are authorized to use customer programs that can respond to hourly signals, if marginal cost-based rates are not feasible or cost-effective. Peninsula Clean Energy (PCE) duly developed an LMS plan, which was approved on April 25, 2024. The plan was submitted to the CEC on May 7, 2024.

Subsequent to that submission, the Peninsula Clean Energy Board approved two measures that help meet the goals of the Load Management Standard: first, joining PG&E’s Hourly Flex Pricing pilots and second, moving forward with potential adoption of a Distributed Energy Resource Management System (DERMS) platform. This plan update reflects these two actions as well as other developments with PCE’s programs.

DISCUSSION
I. Summary of Today’s Request
Since the Board’s approval of PCE’s LMS plan on April 25, 2024, and its submission to the CEC on May 7, 2024, PCE staff has been in close correspondence with CEC staff regarding the approval of the document. After review, CEC staff recommended that PCE's LMS plan be updated to include: (1) PCE's actions to implement the LMS plan, and (2) specificity regarding plans to move customers' energy usage off-peak hours with customer programs. PCE staff has incorporated these updates for Board approval, with both the clean and redlined versions included.
6 The updated plan now reflects:

1. PCE's Board approval of participation in Pacific Gas and Electric Company’s (PG&E) Expanded Pilots 2, and Vehicle to Grid Integration (VGI) Real Time Pricing pilot to comply with the LMS on October 24, 2024, and PCE’s Advice Letter PCEA-039-E on November 1, 2024, noticing the CPUC that PCE is participating PG&E’s Hourly Flex Pricing (HFP) pilots.

2. Further detail on efforts to establish a DERMS platform and other developments in PCE's programmatic efforts.

Since this revision reflects actions already taken by the Board and serves to assist the CEC in approving PCE's LMS plan, staff recommends the approval of the updated PCE LMS plan.

II. Regulatory Background
The CEC established the LMS regulation in April 2023 to require Large CCAs, including PCE, to use MCB rates and programs to encourage energy use at off-peak hours and improve equity, efficiency, and reliability of the electric system. PCE is required to submit an LMS Compliance Plan outlining how PCE will meet the LMS regulation requirements.

The LMS requires PCE to analyze an hourly MCB rate for each customer class based on cost-effectiveness, equity, feasibility, and benefits to decide whether to adopt such rates. If adopted, the MCB rates must be available for customers to enroll in by July 1, 2027. The PCE Board opted to leverage IOU pilots to satisfy this requirement.

If a large CCA were to conclude that the implementation of an MCB rate is not technically feasible, cost-effective, equitable or beneficial, then it must propose cost-effective marginal-cost responsive load flexibility programs for compliance. PCE’s programs are moving toward being able to satisfy this requirement as an alternative pathway if PCE were to decide in the future to discontinue a MCB rate. If adopted, these programs must be available for customer enrollment by July 1, 2027.

III. PCE’s Approach
a. Rate Offerings
The first substantive update of the LMS is a discussion of PCE’s strategy for implementing MCB rates. PCE found, based on substantial evidence in light of the whole record, that designing and implementing its own MCB rates is not likely to be cost-effective or technically feasible as an approach to meeting the goals of the LMS. Instead, to implement PCE’s MCB rates for its residential, commercial, and industrial classes, PCE has chosen to focus staff resources on participation in two of PG&E’s HFP pilots: the Expanded Pilot 2 and the VGI pilots. PCE declined to participate in the Expanded Pilot 1 (Agricultural) because the PCE Board found that this pilot would not be cost-effective due to the small number of agricultural customers among PCE’s customer base and a lack of peak-coincident load. The PCE Board approved participation in PG&E’s Expanded Pilot 2 and VGI pilot to comply with the LMS on October 24, 2024. PCE anticipates enrolling customers in the pilots by June 1, 2025, or earlier if feasible, to comply with CEC regulations.
b. Customer Program Offerings
The second update includes updates to PCE’s program offerings. These programs are not 7 strictly necessary at this time to comply with the LMS standard because of the participation in the HFP pilots. However, these programs could be used in future as an alternate path to compliance if they were upgraded to be able to respond to MCB hourly signals. PCE currently offers a portfolio of load flexibility programs with a diversity of enabling technologies, and different tiers of engagement to provide options for customers. Following is a list of current and planned program offerings, including several pilots that are being tested for reliability, load reduction, and customer adoption: Solar and Storage for Public Buildings, Residential Solar and Storage, FLEXmarket, Residential Electrification Direct Install, and GovEV. Each of these programs is envisioned potentially to become MCB signal-responsive programs to either supplement or serve in place of MCB rates in future years. The timeline and feasibility of the rollout of MCB signals to these load flexibility technologies will be evaluated in future development of PCE’s DERMS platform.

Taken together, these updates document PCE’s actions since the initial plan submittal to advance PCE’s load management strategies to achieve the goals shared by PCE and the CEC.

FISCAL IMPACT
None.

ATTACHMENTS:

Final Revised LMS Compliance Plan (14 MAR 2025).pdf
Final Revised LMS Compliance Plan REDLINES 2(14 MAR 2025).pdf 8 1
Load Management Standard
Compliance Plan
Peninsula Clean Energy Authority
Revised March 15, 2025
9 2

1. Introduction
Peninsula Clean Energy Authority (PCE) supports the overall objectives of the Load Management Standard (LMS) since these strategies are important for PCE’s goal of serving its customers 100% renewable energy on a high time-coincident basis in coming years.

Since this requires the matching of load to the generation of PCE’s contracted variable energy generation resources, load shifting is a critical strategy for PCE to achieve this goal.

PCE looks forward to working with the California Energy Commission (CEC) in the coming years to develop cutting-edge and cost-eMective approaches to achieving the overall goals of the standard.

1.1. About PCE
PCE, a community choice aggregator (CCA), provides electricity service to residents and businesses in San Mateo County and the City of Los Banos in Merced County. Formed in February 2016, PCE is a joint powers authority, consisting of the County of San Mateo, all twenty of its towns and cities, and the City of Los Banos in Merced County. Following a comprehensive feasibility study, consistent with Assembly Bill (AB) 32 voluntary action pathways, elected oMicials from each member jurisdiction unanimously agreed to form PCE to meet their local climate action goals and for the benefit of San Mateo County. In 2020, following another comprehensive feasibility study, elected oMicials from the City of Los Banos voted to join PCE.

PCE provides cleaner electricity, and at lower rates, than the incumbent investor-owned utility (IOU), Pacific Gas and Electric Company (PG&E). PCE plans for and secures commitments from a diverse portfolio of energy-generating resources to reliably serve the electric energy requirements of its customers over the near-, mid-, and long-term planning horizons. PCE was assigned an investment-grade credit rating from Moody’s in May 2019 and S&P in June 2023, the second of the three CCAs in California to obtain investment-grade credit ratings. PCE’s programs include advancing the adoption of electric transportation and transitioning building fossil fuel uses to low-carbon electricity.

As part of its mission-driven, collaborative, not-for-profit, locally focused roots, PCE is committed to two key organizational priorities:
• Deliver 100% renewable energy on an annual basis and align renewable energy supply with customer demand each and every hour of the day in the coming years. • Contribute to San Mateo County reaching the state’s goal to be 100% free of greenhouse gasses (GHG).

PCE is also committed to the following several strategic goals:
• Secure suMicient, low-cost, clean sources of electricity that achieve PCE’s priorities while ensuring reliability and meeting regulatory mandates. • Strongly advocate for public policies that support PCE’s organizational priorities. 10 3
• Implement robust energy programs that reduce GHG emissions, align energy supply and demand, and provide benefits to community stakeholder groups. • Develop a strong brand reputation that drives participation in PCE’s programs while ensuring customer satisfaction.
• Employ sound fiscal strategies to promote long-term organizational sustainability. • Ensure organizational excellence by adhering to sustainable business practices and fostering a workplace culture of innovation, diversity, transparency, and integrity.

The importance of these goals for the communities of San Mateo County is underscored by the 2019 declaration of a climate emergency by the Board of Supervisors calling on local agencies and jurisdictions to work “to achieve carbon neutrality throughout San Mateo County and to implement other actions to address climate change.”1

1.2. The Role of PCE’s Board of Directors
PCE is governed by its Board of Directors (Board). Each member jurisdiction from San Mateo County, plus the city of Los Banos, has one seat on PCE’s Board (except for San Mateo County, which has two) for a total of 23 elected oMicials acting as board members.

In addition, the Board has two board member director emeritus selected from former directors who participate in board activities as non-voting members.

The Board is responsible for setting the overall strategy for PCE, including rate setting and energy procurement decisions.2 The decisions of the Board are binding requirements for PCE.

In addition to operating the CCA program, PCE also implements a range of customer programs to facilitate decarbonization and access to electrification, especially for disadvantaged customers. Generally, PCE does not receive cost recovery from the California Public Utilities Commission (CPUC) for these programs but funds them through rates or grants from outside sources.

1.3. The CEC Load Management Standard
In 1974, the California State Legislature passed the Warren-Alquist Act establishing the CEC. At its inception, the CEC was granted specific authority including but not limited to implementing load management standards.3 The CEC updated these standards in 2022 to 1 County of San Mateo Board of Supervisors, Resolution No. 19-847: Adopt a resolution endorsing the declaration of a climate emergency in San Mateo County that demands accelerated actions on the climate crisis and calls on local jurisdictions and agencies to join together to address climate change (2019). 2 Public Utilities Code § 366.2. 3 California Energy Commission, 2022 Load Management Standards Rulemaking Fact Sheet, 1 (2022), https://www.energy.ca.gov/sites/default/files/2022-10/Load_Management_Fact_Sheet_ADA.pdf 11 4
enhance statewide demand flexibility, and the new amendments eMective as of April 2023 are what this plan addresses.4
The CEC established its LMS regulation based on the definition of load management as “any utility program or activity that is intended to reshape deliberately a utility’s load duration curve.”5 The primary objectives of the regulation are to:
• Encourage energy use at oM-peak hours.
• Encourage daily and seasonal peak load control to improve equity, eMiciency, and reliability of the electric system.
• Decrease or delay the need for new electrical capacity. • Reduce GHG emissions and fossil fuel consumption.

To ensure progress toward these goals, the CEC is requiring California’s large Publicly Owned Utilities (POU), large IOUs, and large CCAs to submit LMS Plans outlining how they will meet the LMS regulation requirements.

The LMS regulation requires each large POU, IOU, and CCA to analyze an optional hourly marginal cost-based (MCB) rate for each customer class. The proposed rate should be evaluated based on five factors: (i) cost-eMectiveness, (ii) equity, (iii) technical feasibility, (iv) benefits to the grid, and (v) benefits to customers. If the CCA deems the implementation of an MCB rate is not feasible based on one or more of the five factors, then it must propose cost-eMective load flexibility programs for compliance and conduct an evaluation using the same five metrics. Compliance may be modified or delayed if the CCA can show that despite good faith eMort, requiring timely compliance would result in reduced system eMiciency or reliability, extreme hardship, technological infeasibility, or lack of cost-eMectiveness to the CCA.
4 20 Cal. Code Regs. §§ 1621-1625. 5 Public Resources Code § 25132. 12 5
Table 1 outlines the goals set forth in the LMS regulation, along with the expected completion date identified by the CEC and PCE’s progress status toward meeting that deadline.

Table 1. Progress Toward LMS Goals
LMS Section Description Deadline PCE Status
§1623.1(c) Upload existing time-dependent rates to
the Market Informed Demand Automation
Server (MIDAS) database.

October 1, 2023 Completed
with ongoing
updates
§1623(c) Provide customers access to their Rate
Identification Numbers (RIN) on billing
statements and in online accounts using
both text and quick-response (QR) code.

March 31, 2024 Awaiting
PG&E billing
changes
§1623.1(a)(1) Develop and submit to PCE’s Board an
LMS plan.

April 1, 2024 Submitted to
the Board
March 22,
2024
§1623.1(a)(3)(A) Submit to the CEC the Board-approved
LMS plan.

May 31, 2024
§1623(c) Develop and submit to the CEC, in
conjunction with the other obligated
utilities, a single statewide RIN access
tool.

Oct. 1, 2024 Ongoing,
through
CalCCA
participation
§1623.1(b)(3) Submit to the CEC a list of load flexibility programs deemed cost e[ective by PCE.

Oct. 1, 2024
§1623.1(a)(3)(C) Submit annual reports to the CEC
demonstrating implementation of plan, as
approved by the PCE Board.

Annually
§1623.1(b)(2) Submit to the PCE Board for approval at
least one MCB rate for the customer
class(es) for which it will materially reduce
peak load.

July 1, 2025
§1623.1(b)(2) O[er customers voluntary participation in either an MCB rate, if approved by the
Board, or a cost-e[ective load flexibility
program.

July 1, 2027
§1623.1(b)(5) Conduct a public information program to
inform and educate a[ected customers
why MCB rates or load flexibility programs
and automation are needed, how they will
be used, and how these rates and
programs can save customers money.

Goal date not
specified
Ongoing
currently
§1623.1(a)(1)(C) Review the plan at least once every 3 years after it is adopted and submit an update to
the PCE Board if there is a material
change.

Triennially
13 6

2. PCE LMS Plan

2.1. Overview
The PCE Board does not find, based on substantial evidence in light of the whole record, that designing and implementing its own MCB rates to be likely to be cost-eMective or technically feasible as an approach to meeting the goals of the LMS, as discussed below, consistent with the findings specified in 20 Cal. Code Regs. § 1623.1(a). However, PCE is participating in two of PG&E’s Hourly Flex Pricing (HFP) rate pilots as a more eMective approach to LMS-compliant rate oMerings. The PCE Board approved participation in PG&E’s Expanded Pilot 2 and Vehicle to Grid Integration (VGI) pilot to comply with the LMS on October 24, 2024. PCE will provide an update on the expansion of the pilots in its next LMS Compliance Plan report. Subsequently, PCE filed Advice Letter (AL) PCEA-039-E on November 1, 2024, noticing the CPUC that PCE is participating PG&E’s HFP pilots.6

2.2. RTP Pilots
To implement PCE’s MCB rates for its residential, commercial, and industrial classes, PCE will focus staM resources on participation in two of PG&E’s HFP pilots: the Expanded Pilot 2 and the VGI pilots. PCE has declined to participate in the Expanded Pilot 1 (Agricultural) because the PCE Board finds that this pilot would not be cost-eMective due to the small number of agricultural customers among PCE’s customer base and a lack of peak-coincident load.

2.2.1. Rate Design
The MCB rates PCE will oMer through PG&E’s HFP pilots will be based on deviations from historical usage at marginal rates driven by dynamic hourly prices. The dynamic prices include marginal generation capacity costs as approved in D.21-11-016 and allocation as specified in D.22-08-002 and marginal energy costs as approved in D.21-11-016, based on PG&E Default Load Aggregation Point (DLAP), adjusted for line losses.7 Marginal transmission and distribution costs will be based on forecasted load on a representative circuit with similar load characteristics to the customer’s circuit, but annual average load-weighted prices will not vary geographically for equity reasons. 8 The rate design will
incorporate a fixed cost collection subscription mechanism as outlined in the California Flexible Unified Signal for Energy (CalFUSE) proposal, with no scalers or adders. 6 Peninsula Clean Energy Authority Advice Letter 049-E “Notice to the Commission of Participation in the PG&E Expanded Pilot 2” (November 1, 2024) available at https://www.peninsulacleanenergy.com/wp-content/uploads/2024/11/PCE-AL-39E_Expanded-Pilot-2-Opt-in-1.pdf 7 Pacific Gas and Electric Company, 2023 LMS Compliance Plan (2023). 8 Pacific Gas and Electric Company, 2023 LMS Compliance Plan (2023). 14 7
The Expanded Pilot 2 and VGI pilots are anticipated to be available without participation limits to all of our residential, commercial, and industrial customers. These pilots are available to all customers based on the terms defined by PG&E and per the regulatory approvals.9 PCE is not imposing any participation cap. Pilot descriptions are included below.
• Expanded Pilot 2: Under the Demand Flexibility proceeding (R.22-07-005), PG&E was directed to expand a pilot program developed by Valley Clean Energy (VCE) and PG&E in response to the 2021 grid reliability challenges.

PG&E must now extend the pilot developed with VCE to serve residential, commercial, and industrial customers. The pilot is being rolled out via “Automation Service Providers” (ASPs), who currently provide automation services to existing devices installed in homes and businesses. PG&E has an enrollment target of 50 MWs under the pilot, which is currently scheduled to conclude by December 31, 2027.
• VGI Pilots: Under the Transportation Electrification proceeding (R.18-12-006), PG&E was directed to develop two VGI pilots with a dynamic pricing rate to serve residential and commercial customers. Both pilots provide upfront incentives for bidirectional electric vehicle (EV) charging equipment in phase 1 and then require customers to enroll under a dynamic pricing rate during phase 2. Across its entire service territory, PG&E is planning to enroll 200 commercial customers under the VGI commercial pilot. The dynamic rate is expected to be available for 12 months under both pilots or until funding is exhausted.

PCE anticipates enrolling customers in the pilots by June 1, 2025, or earlier if feasible, to comply with CEC regulations.

PCE is not participating in PG&E’s Expanded Pilot 1, which targets agricultural customers.

PCE staM determined that oMering a pilot rate program to our agricultural customers would not result in material peak load reduction or be cost eMective, based on the following factors:
• Lack of shiftable peak load: PCE has only 129 agricultural customers which represent 0.4% of PCE’s peak load.
• Administrative burden: The administrative burden of implementing the Expanded Pilot 1 would very likely exceed the benefits gained from the program, and limit staMing resources which could be applied to the pilots more applicable to PCE’s customer base.
9 CPUC Decision 24-01-032, PG&E’s Advice Letter 7222-E1, Advice Letter 7222-E-A2, Advice Letter 7222-E-B3, Advice Letter 7223-E-A4 and Advice Letter 7223-E-B5 for the Expanded Pilots, and PG&E’s Advice Letter 7234-E-A6, and CPUC’s Resolutions E-5192, E-5326 and E-5358 for the Vehicle Grid Integration (VGI) Pilots (Regulatory Approvals), (together the “Hourly Flex Pricing Pilots”, or “HFP Pilots”) 15 8
Since our agricultural customer class is small, and does not have high demand during peak periods, implementing this pilot for agricultural customers would not have a significant eMect on our peak loads, even if participation and responsiveness to MCB rates were high.

Therefore, PCE’s Board did not find it cost eMective to oMer MCB rates to our agricultural customer class.

As PG&E has indicated, it will no longer be able to make the necessary updates to its billing system to implement a more permanent dynamic pricing solution until after July 1, 2027.

We anticipate that the pilot programs will be extended to customers beyond that date, subject to CPUC approval. Should either the CPUC decline to extend these pilots past that date or PCE deem that continued participation is not the most cost-eMective approach to enabling load shifting, PCE will submit an LMS plan revision to update our plan for oMering either MCB rates or marginal cost signal responsive programs to all customer classes for which they are cost eMective, or both, as provided for in 20 Cal. Code Regs. § 1623.1. Until such time as the CPUC makes its decision, such a determination of continued participation would be premature.

In addition to the MCB rate pilots, PCE will continue to deploy programs that can respond to MCB signals, as described below. Under this approach, most or all customers will likely have multiple vehicles for creating load flexibility. Both the MCB rates and the marginal cost signal responsive programs are anticipated to interact with the statewide RIN tool pursuant to 20 Cal Code Regs. § 1623 (c) when it becomes available.

2.3. Evaluation

2.3.1. Cost-E3ectiveness
PCE’s strategy of participation in the CPUC-sponsored pilots is informed by some of the cost and feasibility considerations of designing and implementing its own separate MCB rates. The cost-eMectiveness of any MCB rate oMering depends on whether the value of any load shift to the customer and PCE exceeds the costs of implementation of the proposal.

Evaluation of cost-eMectiveness will be a continuous and ongoing eMort as the results from the HFP pilots become available. Since CCAs are excluded from cost recovery for expenditures in support of wider grid benefits, the analysis of cost-eMectiveness is necessarily narrower than it would be for either IOUs or POUs.

Evaluation of the costs of implementing an MCB rate include a variety of fixed and per-customer costs. Fixed costs include, but are not limited to:
• Personnel costs for staM to design and maintain MCB rates. • Management costs to obtain data from the California Independent System Operator (CAISO) and PG&E to calculate hourly costs.
• Software and system costs for design, maintenance, and operations. 16 9
• Contractor costs to implement MCB rates, including customer education and support.
• Software and upload costs associated with the MIDAS database interface.

In addition to the implementation costs, it is unknown whether and how the CPUC will require PG&E to provide real-time billing quality customer data, the costs associated with obtaining these data, and any required technical or data handling costs. Since PCE would be spreading comparable fixed costs across a small customer base, it is less likely that the value of the marginal improvement in load shifting over PCE’s existing Time-of-Use (TOU) rates would be enough to justify these fixed costs, compared to larger Load Serving Entities (LSE). PCE’s comparable fixed costs would be recovered from a smaller rate base, resulting in higher per-customer costs. PCE anticipates participation in PG&E’s HFP pilots may shed light on some of these costs going forward.

By the same token that the costs of implementation are diMicult to determine, the value of any load shift that might result from an MCB rate is also diMicult or impossible to assess at this time. The value of the load shift depends on participation rate, how much load is shifted, in what hours, and the value of that load shift. In principle, the amount of load shift could be determined for each hour if the elasticity of electricity demand in each hour were known; however, evaluating these elasticities would require considerable data for all hours and would have significant uncertainties. In addition, it would be necessary to know how the MCB rate values would diMer from existing TOU rates in each of these hours.

Currently, several components of the marginal costs would be diMicult to ascertain at this time. While hourly energy costs are currently generated in the CAISO market, the hourly capacity values are unclear. The resource adequacy (RA) program is shifting to a 24-hour slice-of-day framework, which would theoretically generate diMerential values of capacity in diMerent hours. However, until the slice-of-day framework has been in place for some years, it will be impossible to assess what the capacity value of energy use in one hour might be relative to the energy use in a diMerent hour. In addition, there are no currently accepted methodologies in use for the assessment of the hourly value of transmission and distribution costs. As discussed below in the context of technical feasibility, several components of hourly costs are not currently available, making the evaluation of the value of load shift diMicult or meaningless to calculate.

Determining the net value of any load shift would also require oMsetting the cost of serving new load in the hour to which electricity use is shifted. This in turn would require an 17 10
understanding of whether reduced load in various hours would result in overall load reductions (load shed) or a shift to other hours (load shift), and if so, to which hours.

Furthermore, the value of a given shift (e.g., from 8 p.m. to 11 p.m.) is likely to vary by day of the week. Even if only within-day shifts are assessed, this constitutes nearly 50,000 pairwise shifts between hours across the year, even assuming that a single week can be representative of all hours in the month. This calculation would require extremely large quantities of data that are not available at this time. Thus, a full cost-eMectiveness assessment is currently diMicult or infeasible.

Given the diMiculties in evaluating the cost-eMectiveness of an MCB rate today, PCE is strongly interested in the data and key lessons to be derived from participating in CPUC-sponsored IOU pilots. Should the data on both responsiveness and costs be available, PCE anticipates being able to more fully analyze the costs and benefits of such programs in future years.

2.3.2. Equity
Significant equity concerns are raised by MCB rates because any error from the true cost raises the prospect of unrecovered costs. If any kind of adder is required to cover these unrecovered costs, this is likely to represent a cost shift onto non-participating customers.

PCE anticipates that participation in any MCB rate oMering is likely to be primarily by wealthier and more sophisticated customers able to aMord the technology required to truly take advantage of such a rate. Non-participating customers should not bear increased costs because of such rate structures. However, since the actual costs that would be realized are diMicult to determine a priori, costs recovered through MCB rates are likely to be highly variable, as customers are almost guaranteed not to respond as forecast in every billing period. Thus, the MCB rates would need to incorporate conservative assumptions about costs recovered through these rates and err on recovering more costs from participating customers. However, if these rates are intentionally conservative to ensure adequate cost recovery in all billing periods, then the economic benefits of participating would be blunted. As such, ensuring equity impacts are avoided likely limits the utility of MCB rates in the first place.

A second major point of concern is possible exposure of low-income customers to real-time market prices. Customers may elect to sign up for new rates without an understanding of the risks or, because most loads are inelastic, with limited ability to react. This can result in extreme customer costs during extreme weather or other significant events.

2.3.3. Technical Feasibility
MCB rates also face several technical prerequisites that would need to be satisfied before implementation of an MCB rate. PCE faces some of the similar challenges as PG&E, including the lack of transmission and distribution marginal costs currently called for in the regulation. Assessing the hourly and locational costs is diMicult to ascertain with reliable 18 11
methodologies. Consequently, there is no obvious data source to access hourly values to use as inputs to an MCB rate.

In addition, the hourly capacity costs are currently impossible to assess, because CPUC jurisdictional entities are transitioning to a new hourly capacity construct currently. The 24- hour slice-of-day framework will generate diMerential value of capacity in diMerent hours.

However, the CPUC has not finished implementing the slice-of-day methodology and several cost containment proposals remain unresolved. Over time, hourly capacity costs should be established by the market, but until LSEs develop expertise in trading hourly products over some years, it will be impossible to assess the capacity value in each hour.

In addition, since PCE is not its own billing agent, additional prerequisites exist and remain to be resolved including access to billing quality daily-hourly data on a timely basis. This likely requires CPUC action to order PG&E to provide such data to PCE. PCE is an active participant in the DER Data Access proceeding at the CPUC (R.22-11-013) to assist the CPUC in making the requisite data available to enable the rates and programs PCE would like to implement.

PCE strongly supports the goals of load shifting as a key cost-containment strategy, but there are a significant number of prerequisites that remain to be implemented on a usable, statewide basis.

2.3.4. Benefits to the Grid
If PG&E pilots are successful in shifting load to cheaper-to-serve times of day beyond what the TOU rates already achieve, this could provide marginal cost savings in the medium term. However, unpredictable customer behavior may actually impose costs on the grid as well.

The changing nature of the grid supply may mean that this value will diminish as California shifts to a fully decarbonized grid. Variable energy resources vary strongly not just by hour, but seasonally. In PCE’s modeling of achieving a fully decarbonized energy supply that meets PCE’s load on an hourly basis with 100% renewable energy, the most important constraints on the grid are likely to shift from concerns about capacity during net peak load periods to daily energy constraints during seasons with low solar over a 24-hour cycle.

These constraints will arise in winter months, during which lower solar production to charge storage will drive constraints in the early morning hours. A portfolio that has both suMicient generation and storage to be capable of meeting overnight winter loads with diminished generation will have considerable excess energy to serve peak load with zero marginal cost energy at other times of the year. What this means is that if storage is capable of meeting load whenever it occurs, then load shifting from one hour to another will deliver few if any grid benefits. In contrast, shifting load from one season to another would be far more significant, but it is diMicult to conceive of how this might be 19 12
accomplished and whether an MCB rate would incentivize investments in such technologies.

In addition, MCB rates may drive customer behavior in ways that force greater distribution costs. In particular, there are some indications that TOU rates have concentrated EV charging in hours immediately after the end of high TOU rate periods. This can actually increase the need for distribution investment to address new higher peak demands outside of TOU hours. If EV drivers move their charging to a small number of low-price hours in response to MCB rates, peak demand on the distribution circuits during those hours could spike. This would require significant distribution investments to accommodate new, higher peak demand. For example, if MCB rates send a signal to charge during solar hours based on CAISO wholesale market prices, that may drive very high loads on particular distribution circuits, triggering large-scale upgrades. Thus, responding to grid-level signals may drive high costs on specific circuits. Since the bulk of retail rates are made up of transmission and distribution charges, increasing these investments may swamp any benefit seen on energy generation costs. The interplay of these dynamics is diMicult to predict, meaning that the net benefit to the grid from MCB rates is impossible to assess and may result in a net detriment to the grid.

In the medium term, the key analysis is the degree to which an MCB rate will shift load from expensive hours to cheaper ones. However, absent critical data on the hourly elasticity of electricity as described above, that analysis is currently not feasible to do.

2.3.5. Benefits to Customers
The benefits to participating customers depend on whether existing TOU rate diMerentials are greater or less than the hourly diMerences in marginal costs. In theory, if the diMerence between high-rate hours and low-rate hours is less than the hourly diMerences in marginal costs, then shifting to an MCB rate may save customers money if they can shift loads to relatively cheaper hours. Under a TOU rate, customers already save money by shifting load outside of the peak window. The benefit to customers then depends on whether customers would save even more money under an MCB rate, but that depends on the details of how the MCB and TOU rates compare in each hour and which hours customers shift usage to and from. Thus, determining whether customers would or would not realize rate benefits will depend on the actual rates by hour relative to existing TOU rates. Since the MCB rates are not currently feasible to develop, it is not possible to analyze the degree of benefits to customers currently.

3. Rate Identification Number
Since CCA bills are controlled and printed by the IOU billing agent (PG&E in this case), PCE has limited input on the design and placement of Rate Identification Numbers (RIN) on the customer billing statements. However, PCE is working with its third-party provider for data 20 13
management and billing services, Calpine Energy Solutions (Calpine), and PG&E to comply with LMS requirements for RINs.

3.1. RINs and QR Codes on Customer Bills
PCE, Calpine, and PG&E have agreed to utilize the Electronic Data Interchange (EDI) 810 files to pass through RINs to PG&E for inclusion on the customer billing statements. The RINs are expected to be available to customers via billing statements and online customer accounts by April 2024.

Per PG&E’s LMS Compliance Plan, the IOU will include the RIN and QR code on the customer billing statement in the rate schedule code section of the electric service agreement details page. PG&E has stated that it does not plan to include a QR code that links to a webpage.

3.2. Statewide RIN Access Tool
PCE has participated in CEC-led workshops on the development of the Statewide RIN Access Tool and provided input on the process, when able. However, PCE’s involvement in the development of the tool is limited, as it has been with the design and placement of the RINs on the customer billing statements, which IOUs control. Nonetheless, PCE has been working with the other LSEs to design and implement the statewide RIN tool, pursuant to 20 Cal. Code Regs. § 1623(c). A proposed plan for the tool was submitted by a subset of LSEs to the CEC for review on October 1, 2024. We will continue to work with the other LSEs and the CEC to establish appropriate mechanisms for the implementation and maintenance of the statewide RIN tool in a timely manner subject to the tool’s approval by the Commission.

4. Load Flexibility Programs

4.1. Overview
In addition to the MCB rate approach above, PCE is also developing a series of programs that can become MCB signal-responsive programs to either supplement or serve in place of MCB rates in future years. PCE is also pursuing more cost-eMective approaches of “right sizing” transportation and building electrification infrastructure to constrain costs and address peak loads
Load flexibility and grid reliability are key elements of PCE’s decarbonization strategy. PCE has multiple oMerings currently and is exploring a number of additional leading-edge options for its customers. These programs will likely play a central role in PCE’s load-shifting strategy to meet the objective of the LMS. 21 14
PCE has established the following objectives for its distributed resources programs:
• Provide grid benefits, especially peak shaving to reduce wholesale costs and carbon intensity, aiding further penetration of renewables.
• Enable resilience.
• Lower operating costs for customers.
• Make electrification more economically beneficial.
• Create scalable deployment through sustainable models.

PCE’s approach includes a focus on avoiding unnecessary capacity increases which can result in added costs and reliability challenges. This includes guidelines for residential electrification within 100-amp service,
10 use of low-power charging in multi-family
buildings, and fleet infrastructure planning.
11 In addition, PCE programs emphasize
continuous load shaping, in contrast to event-driven curtailment, to maximize the benefits of load shaping for customers and the grid.

PCE has focused on developing a portfolio of flexible and eMective load-shaping programs aimed at significantly reducing grid peak loads. PCE has also worked to innovate with technology and software providers to advance functionality that will allow for broad participation and help maximize potential resources, optimized for customer and grid needs. Multiple approaches are being continually assessed and PCE is learning from these initiatives to inform future program designs and the technology needed to scale adoption.

PCE currently oMers a portfolio of load flexibility programs with a diversity of enabling technologies, and diMerent tiers of engagement to provide options for customers.

Following is a list of current and planned program oMerings, including several pilots that are being tested for reliability, load reduction, and customer adoption.

4.1.2. Solar and Storage for Public Buildings
Overview: Public agencies have significant interest in the deployment of solar and storage systems to reduce costs and provide resilience for power outages and emergencies. In addition, the Inflation Reduction Act’s “direct pay” provisions allow public agencies to access the Investment Tax Credit without an intermediary, improving the economics of distributed generation systems. PCE operates an aggregate solar and storage program aimed at improving the economics of distributed solar and storage for public agencies. This program operates in cohorts in which PCE assumes the role of developer, providing upfront project development services, procurement, and financing under a PCE-supplied power purchase agreement (PPA) for the local government agency. Systems are then deployed by a construction firm under contract with PCE. PCE owns the systems and provides ongoing operations and maintenance support with a performance guarantee. The storage systems will provide backup power for outages and dispatch for grid peak load reduction.

Status: This program was launched in 2020 with significant legal and site development work to establish the program. Construction of the initial 12 systems with 1.7 MW of solar are nearing completion.
12 The second round of the program included 24 sites for approximately 3.5 MW PV is under construction. A third round to incorporate storage is in development. Additional solar and storage sites are in development with as much as 6 MW of storage. Dispatch may be administered directly through a PCE distributed energy resource management system (DERMS), battery management systems, or contractually specified with service providers.

4.1.3. Residential Solar and Storage
Overview: Residential storage systems, typically paired with solar, are growing in popularity. Currently in PCE territory, there are approximately 34,000 systems with a total of

71.6 MW of storage.13 With the state’s adoption of the Net Billing TariM, it is expected that residential solar and storage adoption will grow. PCE has had a residential solar and storage program since 2020. That program has provided outreach and incentives for customers to adopt solar and storage systems. The systems are installed by a competitively selected provider and the storage systems dispatch at the grid peak as specified under the contract between PCE and the provider.

Status: PCE’s residential solar and storage program completed its enrollment phase between 2020 and 2023. Nearly 400 new system installations were completed, and an additional 200 existing systems were enrolled. (PCE is also enabling a further 200-300 systems at low-income customer sites, funded by a combination of the Self-Generation and Investment Tax Credit.) Under the agreement with the provider, the provider oMers 12 US climate law introduces billion-dollar ‘game-changer’ for nonprofits, Canary Media https://www.canarymedia.com/articles/climatetech-finance/us-climate-law-introduces-billion-dollar-game-changer-for-nonprofits 13 Q4 2023 PG&E Interconnection Data for Peninsula Clean Energy service territory 23 16
battery storage dispatch during the evening peak, and PCE purchases the rights to this capacity over a 10-year term. The dispatch capacity is factored into PCE’s annual load forecast submitted to the CEC, and subsequently, the CEC reduces PCE’s forecasted RA capacity as a result of a lower forecasted peak load. PCE is continually working with the provider to further optimize the dispatch schedule to maximize the grid value, such as by concentrating as much energy capacity into a narrower, 2-hour dispatch window. In addition, PCE anticipates developing a follow-on program that will again provide support to homeowners in deploying solar and storage systems, while also providing capacity services to the grid. Dispatch may be administered directly through a PCE DERMS or contractually specified with service providers.

4.1.4. FLEXmarket
Overview: PCE utilizes the innovative FLEXmarket program to provide incentives to project implementers based on the measured grid benefits. PCE is implementing this approach because most energy eMiciency programs do not adequately target load-shaping benefits.

In addition, incentives are not targeted based on grid benefits nor measure actual results.

This program operates across all customer classes for permanent load shifting achieved by targeted energy eMiciency and beneficial electrification. The program utilizes Normalized Metered Energy Consumption (NMEC) methodology to assess projects based on their actual performance weighed against grid benefits with the Avoided Cost Calculator (ACC).

This is a CPUC-funded program.

Status: PCE launched its FLEXmarket program in 2023 for both the commercial and residential sectors and has successfully enrolled projects in the first iteration of the program. Initial program emphasis has been on attracting service providers and proving the general model of the program. PCE anticipates continuing the program subject to CPUC approval.

4.1.5. Residential Electrification Direct Install
Overview: PCE operates an income-qualified direct install program for electric appliances – replacing aging, polluting methane gas systems. This program has upgraded approximately 300 homes with heat pump water heaters or other eMicient electric measures. Under the program, PCE has piloted whole-home electrification of 5 single-family homes to assess costs and demonstrate electrification that minimizes grid impacts by fully electrifying within 100 amps.
14 Finally, PCE has also piloted an advanced load-14 Yes, it’s possible to electrify a home on just 100 amps, Canary Media, https://www.canarymedia.com/articles/electrification/yes-its-possible-to-electrify-a-home-on-just-100- amps
24 17
shaping technology in space and water heating combo systems which can shift load in both applications through the thermal storage and advanced system logic. 15 Status: This program will be substantially expanded in 2024 to allow for whole-home electrification. Numerous innovations are envisioned to be incorporated into this program including electrification within 100 amps, as well as the potential use of advanced combo systems, and integration of load shaping for water heaters and thermostats, possibly through a PCE DERMS. Separate from this program, PCE currently provides incentives to customers for the installation of load-shaping combo systems.

4.1.6. GovEV
Overview: The GovEV program helps local municipal fleets plan for fleet electrification by providing technical assistance for vehicle replacement purchasing and the installation of EV chargers. As a component of this program, PCE produces a charging optimization plan, which outlines the cost potential of managed charging for their specific fleet. PCE is also making the ChargePilot charge management system by The Mobility House free for fleets, as part of the GovEV program for one year. The ChargePilot system (optional to fleets but recommended) will help shift more fleet charging to occur during oM-peak hours and mitigate demand charges, as well as provide insights into EV charging metrics for fleet managers.

Status: The program is open, and 10 fleets are currently enrolled. Installation projects are expected to begin in Calendar Year (CY) 2025.

4.1.7. Electric Vehicle Managed Charging
Overview: PCE ran an EV Managed Charging Pilot in collaboration with EV.energy and researchers at UC Davis but determined that the response was small and the program not cost-eMective. PCE’s territory has one of the state’s fastest adoption rates for EVs with over 45,000 EVs on the road today and EVs accounting for over one-third of new vehicle sales.

Managing EV charging is a high priority for PCE with an emphasis on residential charging, where most evening charging is occurring, and shifting vehicle load daily out of the evening peak. In addition, minimizing the secondary midnight peak that can aMect local distribution networks is also a priority. PCE has focused on leading-edge strategy by using vehicle telematics, which controls EV charging through the vehicle as opposed to charger-based load management. Because the installed base of smart chargers is very small and such chargers are expensive, the telematics approach holds greater promise because nearly all vehicles can participate without special equipment.
15 TRC / Rupam Singla, Harvest Thermal Pilot: Measurement and Verification Report (2023), https://www.peninsulacleanenergy.com/wp-content/uploads/2024/02/PCE-Harvest-Pilot-MV-Final-Report.pdf 25 18
Status: PCE recently completed and analyzed its second phase pilot of managed charging with EV.energy and researchers at UC Davis. The amount of load shift was minor, in large part because customers who opted to participate were more tech-savvy than typical and mostly already shaping their load. In light of the lackluster eMectiveness of the pilot, PCE is not moving forward with this particular program design.

4.1.8. Program Design to Meet LMS Goals
Each of these programs is envisioned to incorporate remote dispatch DERMS or comparable technologies, which will enable all of these programs to become automated MCB signal responsive programs, as envisioned in 20 Cal. Code Regs. § 1623.1(a)(1)(B).

The timeline and feasibility of the rollout of MCB signals to these load flexibility technologies will be evaluated in future development of PCE’s DERMS platform.

4.2. Evaluation
PCE closely evaluates all programs it executes and anticipates that load-shaping programs will be evaluated with the following criteria:
• Amount of grid peak load reduction
• Consistency and reliability of load reduction
• Customer participation rate
• Cost of recruitment and operation
• Customer benefits, impacts, and satisfaction

4.2.1. Cost-E3ectiveness
The costs associated with implementing a new load flexibility program include the following:
• Program development. This includes the costs associated with program design and setup, including integrating such programs with internal and external systems. • Program administration. This involves ongoing costs to administer the program, including marketing, customer recruitment, customer education, development, and maintenance of customer tools, and any upfront or ongoing incentive payments that are part of the design.
• Technology and implementation costs. Each new load flexibility program requires significant investments in new technology platforms. These include external software systems that must be procured to communicate with and dispatch devices, as well as internal systems that must be developed and configured to integrate the external software.

PCE, as a CCA, may derive certain avoided cost value streams such as reduced RA costs and extreme event energy market costs. However, aside from CPUC-funded programs such as FLEXmarket, PCE does not have access to other value streams such as avoided distribution grid costs. Quantification of cost benefits is challenging and of limited 26 19
confidence due to the volatile nature of the energy market, as described in the analysis of MCB rates above.

4.2.2. Equity
PCE has a major focus on equity across its programs. PCE’s primary method of delivering equity benefits is in keeping generation rates low. Since inception, PCE has provided generation rates at least 5% below PG&E for all customers resulting in over $100 million in savings for the community since 2016. In 2024 PCE is currently keeping rates flat resulting in 10-15% savings for customers compared to PG&E for even greater savings. In addition, in December 2023 PCE provided customers in the income-qualified California Alternate Rates for Energy (CARE) / Family Electric Rate Assistance (FERA) programs each a rebate of $300.

PCE has numerous programs targeted at delivering additional equity benefits. These programs include an EV charging incentive and technical assistance for apartment buildings, income-qualified incentives for e-bikes and EVs, and the above-mentioned home direct-install program.

PCE oMerings are geared towards ensuring financial benefits for customers and ensuring access to additional benefits such as functional appliances, etc. Load shaping provides a potential additional tool for reducing customer costs, helping ensure shiftable load is occurring under the most favorable rates. However, most loads in low-income households have little or no shifting capacity. It is essential that households are not penalized for inflexible loads. In addition, while some customer segments are interested in technology it is important that participation not introduce undue complexity, especially in this segment.

Therefore, any technologies introduced need high reliability and eMective passive operation with as little resident intervention as possible.

4.2.3. Technical Feasibility
Load shaping measures as described above have been technically demonstrated by PCE or other parties. PCE currently engages in a “direct control” approach with EVs (a type of DERMS but only for EVs), contractually based load shaping for its residential storage, and a market-based “shaped” incentive structure in FLEXmarket.

However, real-time responsiveness introduces numerous added levels of complexity.

Assets would need to be integrated through a DERMS as a management platform. However, the DERMS landscape is extremely fragmented. Currently, DERMS providers are only able to successfully dispatch a subset of deployed assets, even within an asset type (battery, vehicles, etc.). In addition, customers must retain override capabilities based on specific needs, particularly for batteries which may be needed for power outages in extreme weather, and vehicles for travel needs. Customers, service providers, and manufacturers in many cases can have competing objectives (e.g., backup vs. grid services) and interest in 27 20
enrolling in competing programs. In principle, a portfolio approach could yield confidence that a predictable dispatch capacity can be achieved for an event-based program.

However, PCE’s approach of daily “permanent” load shift oMers the advantage of high predictability for the customer and other parties.

Furthermore, for real-time programs, data integration for the price signals would need to be established reflecting real-time conditions and PG&E billing systems would need to be restructured to allow billing based on those prices. A price signal system must address common standards for calculation, availability of data on a real-time basis, high up-time platform for serving the data, mechanism for customer visibility, and other complexities.

PG&E’s billing system would require major updates of a platform already strained by high complexity, and billing information would need to be presented in a digestible manner for the customer with associated education and customer service support. Both of these areas are major barriers.

4.2.4. Benefits to the Grid
Load shaping provides several grid benefits including reducing costs, increasing reliability, and reducing emissions. Load shaping that is responsive to real-time conditions could potentially increase those benefits to the degree that responsive load shaping is able to provide additional load reductions, above that provided by permanent load shaping, at moments of grid strain.

However, diMerent objectives would necessitate visibility to specific conditions. ISO-level load, transmission congestion, load aggregation points, and distribution circuit conditions each have distinct values that can contribute to the value of load shifting but are not necessarily easily evaluated in real-time by asset controllers, like PCE. Thus, PCE may be able to assess grid value at the level of generation costs but may have diMiculty incorporating other grid benefits, except to the degree that data becomes available for other areas.

4.2.5. Benefits to Customers
Customer benefits of load shaping generally are assessed by PCE in relation to economic value. Specifically, cost reductions after considering customer installation costs and the change in operating costs. As noted above, PCE emphasizes permanent load shifting as a means of maximizing the operating cost benefits. Reliability is also an important benefit though this is diMicult to quantify.

5. Conclusions
PCE strongly supports the goals of the LMS and is already working diligently to implement leading programs and approaches to deliver load flexibility in a cost-eMective and technically feasible manner. Although load-flexibility technologies have many technical 28 21
and policy prerequisites that must be satisfied before such approaches can deliver the full potential benefits, PCE is committed to deepening its current approaches and exploring the feasibility of other approaches as they become available. PCE has committed to participate in the IOU HFP pilots to oMer MCB rates to our customers. PCE anticipates receiving data on eMectiveness and feasibility from that program going forward. While the IOU HFP pilots move forward, PCE is also moving forward on deploying a DERMS platform to enable MCB signal responsive programs as an alternative or supplement to MCB rates in coming years.

Load flexibility is a key tool for PCE’s core objective to provide its customers with 100% renewable energy in all hours. Given PCE’s goals, it anticipates working with the CEC to develop new approaches and to provide real-world, on-the-ground expertise from the lessons derived from this work going forward.
29 1
Load Management Standard
Compliance Plan
Peninsula Clean Energy Authority
Revised March 15, 2025 Deleted: January 30
30 2

Since this requires the matching of load to the generation of PCE’s contracted variable energy generation resources, load shifting is a critical strategy for PCE to achieve this goal.

PCE looks forward to working with the California Energy Commission (CEC) in the coming years to develop cutting-edge and cost-eMective approaches to achieving the overall goals of the standard.

PCE is also committed to the following several strategic goals:
• Secure suMicient, low-cost, clean sources of electricity that achieve PCE’s priorities while ensuring reliability and meeting regulatory mandates. • Strongly advocate for public policies that support PCE’s organizational priorities. 31 3
• Implement robust energy programs that reduce GHG emissions, align energy supply and demand, and provide benefits to community stakeholder groups. • Develop a strong brand reputation that drives participation in PCE’s programs while ensuring customer satisfaction.
• Employ sound fiscal strategies to promote long-term organizational sustainability. • Ensure organizational excellence by adhering to sustainable business practices and fostering a workplace culture of innovation, diversity, transparency, and integrity.

In addition, the Board has two board member director emeritus selected from former directors who participate in board activities as non-voting members.

The Board is responsible for setting the overall strategy for PCE, including rate setting and energy procurement decisions.2 The decisions of the Board are binding requirements for PCE.

1.3. The CEC Load Management Standard
In 1974, the California State Legislature passed the Warren-Alquist Act establishing the CEC. At its inception, the CEC was granted specific authority including but not limited to implementing load management standards.3 The CEC updated these standards in 2022 to 1 County of San Mateo Board of Supervisors, Resolution No. 19-847: Adopt a resolution endorsing the declaration of a climate emergency in San Mateo County that demands accelerated actions on the climate crisis and calls on local jurisdictions and agencies to join together to address climate change (2019). 2 Public Utilities Code § 366.2. 3 California Energy Commission, 2022 Load Management Standards Rulemaking Fact Sheet, 1 (2022), https://www.energy.ca.gov/sites/default/files/2022-10/Load_Management_Fact_Sheet_ADA.pdf 32 4
enhance statewide demand flexibility, and the new amendments eMective as of April 2023 are what this plan addresses.4
The CEC established its LMS regulation based on the definition of load management as “any utility program or activity that is intended to reshape deliberately a utility’s load duration curve.”5 The primary objectives of the regulation are to:
• Encourage energy use at oM-peak hours.
• Encourage daily and seasonal peak load control to improve equity, eMiciency, and reliability of the electric system.
• Decrease or delay the need for new electrical capacity. • Reduce GHG emissions and fossil fuel consumption.

Deleted: an
Deleted: Compliance Plan
33 5
Table 1 outlines the goals set forth in the LMS regulation, along with the expected completion date identified by the CEC and PCE’s progress status toward meeting that deadline.