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)
REVISED AGENDA
Thursday, April 25, 2024
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 3237 Josephine Street, Denver, CO 80205
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 Assistant 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 1 1 . Conference with Legal Counsel – Anticipated Litigation: Discussion of anticipated litigation pursuant to subdivision (d)(2) and (e)(5) of Section 54956.9; One case.
2. Approval of Load Management Standard (LMS) Plan for submission to California Energy Commission (CEC)
3. Approval of A Three-Year Contract with Robert Half & Associates for Temporary Staffing and Recruitment Support
4. Approval of Contract Amendment with David Fribush to increase the contract amount by $260,000 and to extend the term of the Agreement to December 31, 2026
5. Approval of Renewal of Insurance Coverage for the Period from May 1, 2024, through May 1, 2025, at a cost of $197,787
6. Approval of One EV Ready Program Fund Reservation Agreement, Providing Approximately $185,000 in Customer Incentives
7. Approval of Minutes from the October 26, 2023 and February 22, 2024 Board of Directors Meetings
press *6 if you phoned into the meeting, to indicate that you would like to provide comment.
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.
CLOSED SESSION
ACTION TO SET AGENDA AND TO APPROVE CONSENT AGENDA ITEMS 2 8. Chair Report (Discussion)
9. CEO Report (Discussion)
10. CAC Report (Discussion)
11. Approval of Appointments to the Executive Committee and the Audit and Finance Committee (Action)
12. Approval of Updated Peninsula Clean Energy Strategic Plan Organizational Priority Number 1 to: Deliver 100% Renewable Energy on An Annual Basis by 2030 Through Strategic and Cost-Effective Procurement of Resources that Maximize Peninsula Clean Energy 24/7 Hourly Matching of Renewable Energy and Load (Action)
13. Approval of Continued Evaluation and Preparation for a Possible Prepay Bond Transaction, Including Approval to Join the California Community Choice Finance Authority and the Engagement of a Financial Advisor and Prepay Counsel (Action)
14. Approval of New Zero-Carbon Intensity Low Carbon Fuel Standard (LCFS) Eligible Green Tariff for Public Transit Electrification (Action)
15. Committee Members' Reports (Discussion)
16. Marketing, Outreach Activities, and Media Relations Quarterly Report
17. Community Programs Quarterly Report
18. Update on Legislative Activities
19. Acronym List
REGULAR AGENDA
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: March 15, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Jeremy Waen, Senior Director of Regulatory Policy; Doug Karpa, Managing Counsel of Regulatory Policy
SUBJECT: Approval of Load Management Standard (LMS) Plan for submission to California Energy Commission (CEC)
Item No. 2
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
BACKGROUND
Staff seeks authorization from the Board to submit the Load Management Standard (LMS) Plan to the California Energy Commission (CEC) previewed in draft format to the Board during the March 2024 meeting. During that meeting staff provided an overview of the draft LMS Plan. The submission of the LMS Plan to the CEC signifies Peninsula Clean Energy’s first formal step in its ongoing compliance with this new requirement.
Both clean and red-line versions of the LMS Plan are attached. The red-line highlights additional revisions made to the document since the document was last shared with the Board.
DISCUSSION
I. Summary
Peninsula Clean Energy staff have developed a plan to comply with the requirements of the LMS promulgated by the CEC. This standard requires large CCAs to evaluate marginal cost-based, real time priced rate offerings to mitigate electricity usage during peak conditions. In addition, large CCAs may also propose marginal cost responsive programs to further reduce peak loads and shift this electricity use to other, cheaper to serve hours.
The plan proposes to analyze the viability of participation in various CPUC-approved pilot programs implemented by Pacific Gas & Electric (PG&E) to satisfy PG&E’s own obligations under the Load Management Standard. The plan does not propose for Peninsula Clean Energy to develop our own marginal cost-based rates as the costs of implementation and technical challenges are likely to render such rates infeasible. In addition, the plan would leverage Peninsula Clean Energy’s existing and planned customer programs to promote load flexibility for our customers. 6 II. Regulatory Background
The California Energy Commission (CEC) established the Load Management Standard (LMS) regulation in April of 2023. The goals of the standard are: (1) to encourage energy use at off-peak hours; (2) to encourage daily and seasonal peak load control to improve equity, efficiency, and reliability of the electric system; (3) to decrease or delay the need for new electrical capacity; and (4) to reduce greenhouse gas emissions and fossil fuel consumption. To ensure progress toward these goals, the CEC is requiring large Community Choice Aggregators (CCA) to submit an LMS Compliance Plan outlining how Peninsula Clean Energy will meet the LMS regulation requirements.
The LMS requires large CCAs to analyze an hourly marginal cost-based (MCB) rate for each customer class. The proposed rate should be evaluated based on five factors: (i) cost-effectiveness, (ii) equity, (iii) technical feasibility, (iv) benefits to the grid, and (v) benefits to customers. If adopted, the MCB rates must be available for customers to enroll in by July 1, 2027.
If the CCA concludes that the implementation of an MCB rate is not feasible based on one or more of the five factors listed above, then it must propose cost-effective marginal-cost responsive 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 effort, requiring timely compliance would result in reduced system efficiency or reliability, extreme hardship, technological infeasibility, or lack of cost-effectiveness to the CCA. If adopted, these programs must be available for customer enrollment by the same date of July 1, 2027.
III. Peninsula Clean Energy’s proposed implementation of the Load Management Standard. a. Rate Offerings
Peninsula Clean Energy Authority strongly supports the intent of the CEC’s LMS regulation and is already making progress toward achieving load shifting among PCE’s customers. Shifting load from high cost-to-serve hours to less costly hours is a key cost containment strategy for achieving a portfolio that delivers 100% renewable energy on a time-coincident basis. Although Peninsula Clean Energy has not developed a rate to achieve load shifting, Peninsula Clean Energy’s suite of customer programs should deliver real load shifting benefits in alignment with the CEC’s priorities set forth in the LMS.
Instead of developing its own marginal cost-based rates, Peninsula Clean Energy will explore participation in PG&E’s Real-Time Pricing (RTP) rate pilots. However, our participation faces several preconditions that must be satisfied before participation will be feasible, including implementation of data access, billing requirements, and other requirements. Since the costs, benefits, and feasibility of participation in these pilots cannot be determined before the pilots are fully designed and implemented, Peninsula Clean Energy lays out its approach to assessing these pilots as information becomes available. b. Customer Program Offering
In addition, Peninsula Clean Energy is modifying existing customer programs and 7 developing new load flexibility programs in the coming years that can satisfy the CEC’s goals. Peninsula Clean Energy anticipates using automated distributed energy resources to shift load in response to hourly signals, although significant technical prerequisites exist. The programs include EV managed charging programs, solar and storage for public buildings, residential solar and storage, the FLEXmarket program, and residential electrification direct install programs. These programs will incorporate real time signals as the technology and regulatory structures to support this functionality become available.
These technical prerequisites that must be satisfied before these programs become fully feasible to satisfy the LMS include the availability of real-time transmission and distribution signals, integrating hourly and locational energy pricing, rules and processes for identifying and addressing dual enrollments, obtaining timely hourly billing quality data from PG&E, and other technical issues.
Many of these requirements, and the markets that are required for automated distributed energy resources (DER) to significantly expand in the state, will depend on regulatory action by the CPUC and therefore have an uncertain timeline. Absent these prerequisites, PCE’s programs will still be able to shift load in conformity with the goals of the LMS program, although perhaps not with the hourly specificity envisioned by the CEC.
Although technical hurdles remain to fully implement the CEC’s vision, Peninsula Clean Energy has a clear strategy laid out in the attached LMS Plan for deployment of load management strategies to achieve the goals shared by Peninsula Clean Energy and the CEC.
FISCAL IMPACT
Presently, none.
There may be fiscal impacts for Peninsula Clean Energy at a later stage in the LMS process if we adopt rate(s) and/or program(s) that comply with this requirement. The fiscal impacts for those offerings will be considered when those matters are brought to the Board for review and approval.
ATTACHMENTS:
DRAFT LMS Compliance Plan_REDLINE.pdf
REVISED FINAL DRAFT LMS Compliance Plan.pdf
8 Load Management Standard
Compliance Plan
Peninsula Clean Energy Authority
9 Executive Summary
The California Energy Commission (CEC) established the Load Management Standard (LMS) regulation in April of 2023. The driving factors for the implementation of such standards are: (1) to encourage energy use at oE-peak hours; (2) to encourage daily and seasonal peak load control to improve equity, eEiciency, and reliability of the electric system; (3) to decrease or delay the need for new electrical capacity; and (4) to reduce greenhouse gas emissions and fossil fuel consumption. To ensure progress toward these goals, the CEC is requiring California’s large Publicly Owned Utilities (POU), large Investor-Owned Utilities (IOU), and large Community Choice Aggregators (CCA) to submit an LMS Compliance Plan outlining how they will meet the LMS regulation requirements.
The LMS regulation requires each large utility or, as in this case, 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-eEectiveness, (ii) equity, (iii) technical feasibility, (iv) benefits to the grid, and (v) benefits to customers. If adopted, the MCB rates must be available for customers to enroll in by July 1, 2027.
If the CCA deems the implementation of an MCB rate is not feasible based on one or more of the five factors listed above, then it must propose cost-eEective marginal-cost responsive 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 eEort, requiring timely compliance would result in reduced system eEiciency or reliability, extreme hardship, technological infeasibility, or lack of cost-eEectiveness to the CCA. If adopted these programs must be available for customer enrollment by the same date of July 1, 2027.
Peninsula Clean Energy Authority (PCE) supports the intent of the CEC’s LMS regulation since load management is a key cost-containment strategy in achieving its goal of delivering 100% renewable energy on a high time-coincident basis in its 2020-2025 Strategic Plan. The load flexibility programs outlined in this LMS plan demonstrate how PCE’s current eEorts align with the CEC’s priorities set forth via the LMS regulation.
Instead of developing its own MCB rates, PCE will explore participation in Pacific Gas and Electric Company’s (PG&E) Real-Time Pricing (RTP) rate pilots. However, participation faces several preconditions that must be satisfied before participation will be feasible, including approval and implementation by the California Public Utilities Commission (CPUC), implementation of data access, billing requirements, and other requirements critical for CCA participation. Since the costs, benefits, and feasibility of participation in these pilots cannot be determined at this time, PCE lays out its approach to assessing these pilots as information becomes available.
10 In addition, PCE is also developing load flexibility programs in the coming years that can also serve to satisfy the CEC’s goals. These programs include enhancements of existing load modification programs as well as the implementation of new programs. PCE anticipates using automated distributed energy resources to shift load in response to hourly signals, although significant technical prerequisites exist. These prerequisites include the availability of real-time transmission and distribution signals, integrating hourly and locational energy pricing, rules and processes for identifying and addressing dual enrollments, obtaining timely hourly billing quality data from PG&E, and other technical issues. Many of these requirements, and the markets that are required for automated distributed energy resources (DER) to significantly expand in the state, will depend on regulatory action by the CPUC and therefore have an uncertain timeline. Absent these prerequisites, PCE’s programs will still be able to shift load in conformity with the goals of the LMS program, although perhaps not with the hourly specificity envisioned by the CEC.
As developments in these areas proceed, PCE will be moving forward aggressively to implement one or more load management strategies to accomplish the goals of the regulation.
11 Table of Contents
1. INTRODUCTION 1
1.1. ABOUT PCE 1
1.2. THE ROLE OF PCE’S BOARD OF DIRECTORS 2
1.3. THE CEC LMS 2
2. PCE LMS PLAN 5
2.1. OVERVIEW 5
2.2. RTP PILOTS 5
2.2.1. RATE DESIGN 6
2.3. EVALUATION 7
2.3.1. COST-EFFECTIVENESS 7
2.3.2. EQUITY 9
2.3.3. TECHNICAL FEASIBILITY 10
2.3.4. BENEFITS TO THE GRID 10
2.3.5. BENEFITS TO CUSTOMERS 11
3. RATE IDENTIFICATION NUMBER (RIN) 12
3.1. RINs AND QR CODES ON CUSTOMER BILLS 12
3.2. STATEWIDE RIN ACCESS TOOL 12
4. LOAD FLEXIBILITY PROGRAMS 12
4.1. OVERVIEW 12
4.1.1. ELECTRIC VEHICLE MANAGED CHARGING 13
4.1.2. SOLAR AND STORAGE FOR PUBLIC BUILDINGS 14
4.1.3. RESIDENTIAL SOLAR AND STORAGE 15
4.1.4. FLEXMARKET 15
4.1.5. RESIDENTIAL ELECTRIFICATION DIRECT-INSTALL 16
4.1.6. GOVEV 16
4.1.7. PROGRAM DESIGN TO MEET LMS GOALS 16
4.2. EVALUATION 17
4.2.1. COST-EFFECTIVENESS 17
4.2.2. EQUITY 17
4.2.3. TECHNICAL FEASIBILITY 18
4.2.4. BENEFITS TO THE GRID 19
4.2.5. BENEFITS TO CUSTOMERS 19
5. CONCLUSIONS 19
Deleted: 1
Deleted: 1
Deleted: 4
Deleted: 5
Deleted: PROGRAM DESIGN TO MEET LMS GOALS
Deleted: 6
Deleted: 6
Deleted: 7
Deleted: 8
Deleted: 8
12 13
1 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-eJective 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 oJicials 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 oJicials 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 suJicient, low-cost, clean sources of electricity that achieve PCE’s priorities while ensuring reliability and meeting regulatory mandates. 14 2
• Strongly advocate for public policies that support PCE’s organizational priorities. • 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 oJicials 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 LMS
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 15 3
enhance statewide demand flexibility, and the new amendments eJective 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 oJ-peak hours.
• Encourage daily and seasonal peak load control to improve equity, eJiciency, 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 an LMS Compliance Plan 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-eJectiveness, (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-eJective 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 eJort, requiring timely compliance would result in reduced system eJiciency or reliability, extreme hardship, technological infeasibility, or lack of cost-eJectiveness to the CCA.
4 20 Cal. Code Regs. §§ 1621-1625. 5 Public Resources Code § 25132. 16 4
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
17 5
2. PCE LMS Plan
2.1. Overview
PCE does not view designing and implementing its own MCB rates as likely to be cost-eJective or technically feasible as an approach to meeting the goals of the LMS, as discussed below. However, PCE is exploring participation in PG&E’s Real-Time Pricing (RTP) rate pilots as a more eJective approach to LMS-compliant rate oJerings. PG&E filed its Expanded Pilots Proposal with the CPUC on September 25, 2023, requesting to make LMS-compliant modifications to the Agricultural Flexible Irrigation Technology (AgFIT) program.
PCE is exploring participation in PG&E’s Expanded Pilots, Business Electric Vehicle (BEV), and Vehicle to Grid Integration (VGI) RTP pilots to fully comply with the LMS. PCE will provide an update on the expansion of the pilots in its next LMS Compliance Plan report.
2.2. RTP Pilots
The status of PG&E’s RTP pilots is in flux as the IOU is awaiting feedback from the CPUC regarding its expansion requests. PG&E details how the expanded pilots will comply with LMS in its LMS Compliance Plan submitted October 2, 2023.
Pilots are in progress and proposed for PG&E’s service area, which have made (or will make) RTP rates available to customers in the next few years. These pilots will continue to provide important learnings to inform RTP rate design. The Valley Clean Energy (VCE) AgFIT agricultural water pumping pilot is available to agricultural customers in VCE’s service area and includes both marginal generation and distribution cost components. Additionally, PG&E is in the process of implementing a Vehicle-to-Grid Integration RTP Pilot (VGI RTP Pilot) approved by CPUC Resolution E-5192 per directives in CPUC Decision (D.) D.20-12-029. The VGI RTP Pilot is targeted for rollout in 2024. In PG&E’s 2020 General Rate Case (GRC) Phase II, RTP rate pilots were approved for Residential, Commercial, and Industrial customers.
However, these pilots were designed to include only dynamic generation price components and would not meet the LMS requirements to include hourly distribution and transmission marginal cost signals. On September 25, 2023, PG&E filed a proposal – in support of the CPUC Energy Division Sta[’s proposal in Track B of the CPUC’s DFOIR proceeding – to expand the VCE AgFIT Pilot (PG&E Expanded Pilots Proposal). With this proposed pilot expansion, all PG&E-customer classes – except Commercial Electric Vehicle (CEV) and Street Lighting – would be able to enroll in an RTP rate with dynamic generation and dynamic distribution cost components by June 2024. This implementation timing is dependent, however, on PG&E receiving CPUC approvals for these pilots by November 30, 2023. If the PG&E Expanded Pilots Proposal is adopted and implemented on the schedule proposed by the CPUC (June 2024), PG&E will meet the requirements of the LMS to have marginal cost-based hourly rates available to all customer classes (except for CEV) 18 6
for the generation and distribution components of the RTP rates well ahead of the Jan 2027 CEC target.
If PG&E’s proposal for including other customer classes (in addition to Agricultural) – as described in the PG&E Expanded Pilots Proposal – is adopted in the DFOIR proceeding, PG&E will be working with PG&E’s GRC II RTP Track settling parties to pause PG&E’s GRC II RTP pilot rates for the E-ELEC (Residential), B-6 (Small to Medium Commercial) and B-20 (Large Commercial and Industrial) rates. This will allow PG&E to replace those pilots with an RTP rate structure that includes not only marginal generation, but also marginal distribution cost components.
PG&E will provide an update on the plans to provide an LMS-compliant RTP rate for CEV customers by January 2027 in its next annual LMS Compliance Plan report.
Although the VGI Pilot Dynamic Rate includes dynamic generation and distribution, eligibility is limited – in order for CEV customers to enroll in phase 2 of that pilot, they must be interconnected under Rule 21. Interconnection under Rule 21 is required because the VGI Pilot’s objective is to encourage export to the grid and testing of vehicle-to-grid use cases. The VGI Pilot is a short-term pilot and is unlikely to be open to customers all the way to 2027. However, eligibility and a timeframe for the VGI dynamic rates could potentially be expanded to non-Rule 21 CEV customers.
Learnings from the Day-Ahead Real Time Pricing - Commercial Electric Vehicle (DAHRTP-CEV) opt-in rate, the CEV non-NEM export pilot – planned to launch in February 2024 – and the VGI Pilots Dynamic Rate targeted for Q3 2024 would be used to inform the design of the LMS-compliant RTP rate for CEV customers.6 PCE has participated in the proceeding developing these pilots and has expressed interest in participating in PG&E’s Expanded Pilots and BEV and VGI RTP pilots. Should PG&E receive approval from the CPUC to make the pilots LMS compliant, PCE will further evaluate engagement in the pilots as a means to achieve its own LMS goals, based on the details of the final implementation of these programs.
2.2.1. Rate Design
PG&E states the following regarding its plan for an LMS-compliant rate.
While still undergoing minor adjustments, PG&E’s currently preferred rate design will likely be similar to the rate design of its VGI RTP Pilot and will satisfy all but one of the LMS requirements – hourly transmission costs. The VGI RTP Pilot rate design includes marginal energy costs, marginal generation capacity costs, and marginal distribution capacity costs, but does not include hourly transmission costs ... While 6 Pacific Gas and Electric Company, 2023 LMS Compliance Plan (2023). 19 7
the VGI RTP Pilot rate design does not include marginal transmission capacity costs, PG&E is developing a roadmap toward an LMS-compliant rate in 2027.7 PG&E has outlined the details of its RTP rate and proposed the following for inclusion. • Frequency. Individual hourly prices updated on a day-ahead basis. • Marginal Capacity Costs. Marginal generation capacity costs as approved in D.21- 11-016 and allocation as specified in D.22-08-002.
• Marginal Energy Costs. Marginal energy costs as approved in D.21-11-016. These “are the CAISO energy prices at the PG&E Default Load Aggregation Point (DLAP), adjusted for line losses.”8
• Marginal Transmission and Distribution Costs. Dynamic distribution signal created “to recover the Primary Distribution Capacity Costs approved in CPUC D.21- 11-016. The hourly prices will vary depending on the location of the customer and will utilize the scarcity pricing concept, with prices dependent on the forecasted load on a representative circuit with similar load characteristics to the customer’s circuit. As described in the Joint IOU WG 1 Proposal, hourly distribution prices will be set so that average prices are the same across all locations – prices on more constrained circuits will have more time diJerentiation, but annual average load-weighted prices will not vary geographically for equity reasons.”9 • Fixed Costs. Fixed cost collection subscription mechanism as outlined in the California Flexible Unified Signal for Energy (CalFUSE) proposal, with no scalers or adders to denote the collection.
As previously stated, PCE will explore whether to adopt similar rates if PG&E implements an RTP rate in the future.
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-eJectiveness of any MCB rate oJering depends on whether the value of any load shift to the customer and PCE exceeds the costs of implementation of the proposal.
Since CCAs are excluded from cost recovery for expenditures in support of wider grid benefits, the analysis of cost-eJectiveness is necessarily narrower than it would be for either IOUs or POUs.
7 Id.
8 Id.
9 Id.
20 8
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 staJ 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. • Contractor costs to implement MCB rates, including customer education and support.
• Software and upload costs associated with the MIDAS database interface.
In addition, per-customer costs include, but are not limited to:
• Data charges
• Vendor charges
At this time, the costs associated with the creation, implementation, and maintenance of the MCB rates are diJicult to ascertain because many elements are still unknown. 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. However, for comparison, the Sacramento Municipal Utility District (SMUD) anticipates these fixed costs would be larger than the value of the marginal improvement in load over existing time-of-use (TOU) rates.10 Since PCE would be spreading comparable fixed costs across a customer base that is approximately a fifth the size of SMUD’s customer base, it is far less likely that the value of the marginal improvement in load shifting over PCE’s existing TOU rates would be enough to justify these fixed costs. PCE’s comparable fixed costs would be recovered from a smaller rate base, resulting in higher per-customer costs.
By the same token that the costs of implementation are diJicult to determine, the value of any load shift that might result from an MCB rate is also diJicult 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 diJer from existing TOU rates in each of these hours.
Currently, several components of the marginal costs would be diJicult to ascertain at this time. While hourly energy costs are currently generated in the CAISO market, the hourly 10 Sacramento Municipal Utility District, Sacramento Municipal Utility District Comments - SMUD's Load Management Standard (LMS) Compliance Plan (Attachment A) (2023). 21 9
capacity values are unclear. The resource adequacy (RA) program is shifting to a 24-hour slice-of-day framework, which would theoretically generate diJerential values of capacity in diJerent 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 diJerent 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 diJicult or meaningless to calculate.
Determining the net value of any load shift would also require oJsetting the cost of serving new load in the hour to which electricity use is shifted. This in turn would require an 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-eJectiveness assessment is currently diJicult or infeasible.
Given the diJiculties in evaluating the cost-eJectiveness of an MCB rate today, PCE is interested in participating in CPUC-sponsored IOU pilots. Such pilot programs with robust participation from all customer classes could provide some data on the sensitivity of electricity use to MCB rates. This is one contributing factor to PCE’s interest in participating in PG&E’s rate pilots to generate such information.
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 oJering is likely to be primarily by wealthier and more sophisticated customers able to aJord 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 diJicult 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 cost 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 22 10
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 diJicult to ascertain with reliable 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 diJerential value of capacity in diJerent 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 Load Serving Entities 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 hourly data on a time basis. This likely requires CPUC action to order PG&E to provide such data to PCE.
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 the MCB rate is 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 Deleted: However, t
23 11
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 the 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 suJicient 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 diJicult to conceive of how this might be 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 electric vehicle (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 accomodate 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 diJicult 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 diJerentials are greater or less than the hourly diJerences in marginal costs. In theory, if the diJerence between high-rate hours and low-rate hours is less than the hourly diJerences 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 from 24 12
and to which hours. 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 (RIN)
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 RINs on the customer billing statements.
However, PCE is working with its third-party provider for data 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, just like it is with the design and placement of the RINs on the customer billing statements. PCE and other stakeholders are currently waiting for PG&E to propose a timeline for the development of the Statewide RIN Access Tool.
4. Load Flexibility Programs
4.1. Overview
Load flexibility and grid reliability are key elements of PCE’s decarbonization strategy. PCE has multiple oJerings currently and is exploring a number of additional leading-edge options for its customers. Currently, these programs appear likely to play a central role in PCE’s load-shifting strategy to meet the objective of the LMS, especially if participation in the RTP pilots proves unworkable.
25 13
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,
11 use of low-power charging in multi-family
buildings, and fleet infrastructure planning.
12 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 eJective 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 oJers a portfolio of load flexibility programs with a diversity of enabling technologies, and diJerent tiers of engagement to provide options for customers.
Following is a list of current and planned program oJerings, including several pilots that are being tested for reliability, load reduction, and customer adoption.
4.1.1. Electric Vehicle Managed Charging
Overview: PCE 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 aJect 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 11 Blake Herrschaft, Design Guidelines for Home Electrification, 7-12 (2023), https://www.peninsulacleanenergy.com/wp-content/uploads/2023/04/Design-guidelines-for-home-electrification-v041223.pdf 12 San Carlos Case Study: EV chargers for your fleet, less is more, Peninsula Clean Energy, https://www.peninsulacleanenergy.com/san-carlos-case-study-ev-chargers-for-your-fleet-less-is-more/; Access to slow EV chargers could speed up EV adoption among renters, Canary Media, https://www.canarymedia.com/articles/ev-charging/access-to-slow-ev-chargers-could-speed-up-ev-adoption-among-renters Deleted: electric vehicles (
Deleted: )
26 14
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.
Status: PCE recently completed its second phase pilot of managed charging. The first phase was a proof of concept executed in 2020 with 7 vehicles. The proof of concept successfully demonstrated curtailment of charging at peak while ensuring drivers received the charging necessary for their daily needs. Following a competitive solicitation, PCE launched its second-phase pilot demonstrating scaled operation of EV-managed charging.
PCE selected EV.energy as its partner and engaged researchers at UC Davis to develop an experimental design to evaluate incentive structures and assess outcomes. About 700 vehicles participated in the second-phase pilot. Data collection has been completed and analysis is underway. PCE anticipates finalizing its ongoing program design and ramping up its recruitment in the coming months. Incentives to sign up are oJered to EV purchasers through PCE’s income-qualified used EV incentive in addition to direct marketing to customers.
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. Initial 12 systems with 1.7 MW of solar are now completing construction.
13 The second round of the program is in contracting. The initial installations are the solar portion, and storage is intended to be added to select sites. 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. 13 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 27 15
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.14 With the state’s adoption of the Net Billing TariJ, 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. Under the agreement with the provider, the provider oJers 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 cost energy eJiciency 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 eJiciency 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.
14 Q4 2023 PG&E Interconnection Data for Peninsula Clean Energy service territory 28 16
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 eJicient 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.
15 Finally, PCE has also piloted an advanced load-shaping technology in space and water heating combo systems which can shift load in both applications through the thermal storage and advanced system logic. 16 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 oJ-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. 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). 15 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
16 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 Formatted: Font: Bold
Formatted: Font: Bold
29 17
The timeline and feasibility of the rollout of these technologies will be evaluated in future development of these programs.
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 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 30 18
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 oJerings 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 eJective 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 (ex: backup vs. grid services) and interest in 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 oJers 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. 31 19
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, diJerent 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 diJiculty 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 diJicult 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-eJective and technically feasible manner. Although load-flexibility technologies have many technical 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.
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.
32 Load Management Standard
Compliance Plan
Peninsula Clean Energy Authority
33 Executive Summary
The California Energy Commission (CEC) established the Load Management Standard (LMS) regulation in April of 2023. The driving factors for the implementation of such standards are: (1) to encourage energy use at off-peak hours; (2) to encourage daily and seasonal peak load control to improve equity, efficiency, and reliability of the electric system; (3) to decrease or delay the need for new electrical capacity; and (4) to reduce greenhouse gas emissions and fossil fuel consumption. To ensure progress toward these goals, the CEC is requiring California’s large Publicly Owned Utilities (POU), large Investor-Owned Utilities (IOU), and large Community Choice Aggregators (CCA) to submit an LMS Compliance Plan outlining how they will meet the LMS regulation requirements.
The LMS regulation requires each large utility or, as in this case, 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-effectiveness, (ii) equity, (iii) technical feasibility, (iv) benefits to the grid, and (v) benefits to customers. If adopted, the MCB rates must be available for customers to enroll in by July 1, 2027.
If the CCA deems the implementation of an MCB rate is not feasible based on one or more of the five factors listed above, then it must propose cost-effective marginal-cost responsive 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 effort, requiring timely compliance would result in reduced system efficiency or reliability, extreme hardship, technological infeasibility, or lack of cost-effectiveness to the CCA. If adopted these programs must be available for customer enrollment by the same date of July 1, 2027.
Peninsula Clean Energy Authority (PCE) supports the intent of the CEC’s LMS regulation since load management is a key cost-containment strategy in achieving its goal of delivering 100% renewable energy on a high time-coincident basis in its 2020-2025 Strategic Plan. The load flexibility programs outlined in this LMS plan demonstrate how PCE’s current efforts align with the CEC’s priorities set forth via the LMS regulation.
Instead of developing its own MCB rates, PCE will explore participation in Pacific Gas and Electric Company’s (PG&E) Real-Time Pricing (RTP) rate pilots. However, participation faces several preconditions that must be satisfied before participation will be feasible, including approval and implementation by the California Public Utilities Commission (CPUC), implementation of data access, billing requirements, and other requirements critical for CCA participation. Since the costs, benefits, and feasibility of participation in these pilots cannot be determined at this time, PCE lays out its approach to assessing these pilots as information becomes available.
34 In addition, PCE is also developing load flexibility programs in the coming years that can also serve to satisfy the CEC’s goals. These programs include enhancements of existing load modification programs as well as the implementation of new programs. PCE anticipates using automated distributed energy resources to shift load in response to hourly signals, although significant technical prerequisites exist. These prerequisites include the availability of real-time transmission and distribution signals, integrating hourly and locational energy pricing, rules and processes for identifying and addressing dual enrollments, obtaining timely hourly billing quality data from PG&E, and other technical issues. Many of these requirements, and the markets that are required for automated distributed energy resources (DER) to significantly expand in the state, will depend on regulatory action by the CPUC and therefore have an uncertain timeline. Absent these prerequisites, PCE’s programs will still be able to shift load in conformity with the goals of the LMS program, although perhaps not with the hourly specificity envisioned by the CEC.
As developments in these areas proceed, PCE will be moving forward aggressively to implement one or more load management strategies to accomplish the goals of the regulation.
35 Table of Contents
1. INTRODUCTION 1
1.1. ABOUT PCE 1
1.2. THE ROLE OF PCE’S BOARD OF DIRECTORS 2
1.3. THE CEC LMS 2
2. PCE LMS PLAN 5
2.1. OVERVIEW 5
2.2. RTP PILOTS 5
2.2.1. RATE DESIGN 6
2.3. EVALUATION 7
2.3.1. COST-EFFECTIVENESS 7
2.3.2. EQUITY 9
2.3.3. TECHNICAL FEASIBILITY 10
2.3.4. BENEFITS TO THE GRID 10
2.3.5. BENEFITS TO CUSTOMERS 11
3. RATE IDENTIFICATION NUMBER (RIN) 12
3.1. RINs AND QR CODES ON CUSTOMER BILLS 12
3.2. STATEWIDE RIN ACCESS TOOL 12
4. LOAD FLEXIBILITY PROGRAMS 12
4.1. OVERVIEW 12
4.1.1. ELECTRIC VEHICLE MANAGED CHARGING 13
4.1.2. SOLAR AND STORAGE FOR PUBLIC BUILDINGS 14
4.1.3. RESIDENTIAL SOLAR AND STORAGE 15
4.1.4. FLEXMARKET 15
4.1.5. RESIDENTIAL ELECTRIFICATION DIRECT-INSTALL 16
4.1.6. GOVEV 16
4.1.7. PROGRAM DESIGN TO MEET LMS GOALS 16
4.2. EVALUATION 17
4.2.1. COST-EFFECTIVENESS 17
4.2.2. EQUITY 17
4.2.3. TECHNICAL FEASIBILITY 18
4.2.4. BENEFITS TO THE GRID 19
4.2.5. BENEFITS TO CUSTOMERS 19
5. CONCLUSIONS 19
36 1
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-effective 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 officials 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 officials 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 sufficient, low-cost, clean sources of electricity that achieve PCE’s priorities while ensuring reliability and meeting regulatory mandates. 37 2
• Strongly advocate for public policies that support PCE’s organizational priorities. • 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 officials 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 LMS
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 38 3
enhance statewide demand flexibility, and the new amendments effective 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 off-peak hours.
• Encourage daily and seasonal peak load control to improve equity, efficiency, 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 an LMS Compliance Plan 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-effectiveness, (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-effective 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 effort, requiring timely compliance would result in reduced system efficiency or reliability, extreme hardship, technological infeasibility, or lack of cost-effectiveness to the CCA.
4 20 Cal. Code Regs. §§ 1621-1625.
5 Public Resources Code § 25132.
39 4
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 effective 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) Offer customers voluntary participation in either an MCB rate, if approved by the
Board, or a cost-effective load flexibility
program.
July 1, 2027
§1623.1(b)(5) Conduct a public information program to
inform and educate affected 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
40 5
2. PCE LMS Plan
2.1. Overview
PCE does not view designing and implementing its own MCB rates as likely to be cost-effective or technically feasible as an approach to meeting the goals of the LMS, as discussed below. However, PCE is exploring participation in PG&E’s Real-Time Pricing (RTP) rate pilots as a more effective approach to LMS-compliant rate offerings. PG&E filed its Expanded Pilots Proposal with the CPUC on September 25, 2023, requesting to make LMS-compliant modifications to the Agricultural Flexible Irrigation Technology (AgFIT) program.
PCE is exploring participation in PG&E’s Expanded Pilots, Business Electric Vehicle (BEV), and Vehicle to Grid Integration (VGI) RTP pilots to fully comply with the LMS. PCE will provide an update on the expansion of the pilots in its next LMS Compliance Plan report.
2.2. RTP Pilots
The status of PG&E’s RTP pilots is in flux as the IOU is awaiting feedback from the CPUC regarding its expansion requests. PG&E details how the expanded pilots will comply with LMS in its LMS Compliance Plan submitted October 2, 2023.
Pilots are in progress and proposed for PG&E’s service area, which have made (or will make) RTP rates available to customers in the next few years. These pilots will continue to provide important learnings to inform RTP rate design. The Valley Clean Energy (VCE) AgFIT agricultural water pumping pilot is available to agricultural customers in VCE’s service area and includes both marginal generation and distribution cost components. Additionally, PG&E is in the process of implementing a Vehicle-to-Grid Integration RTP Pilot (VGI RTP Pilot) approved by CPUC Resolution E-5192 per directives in CPUC Decision (D.) D.20-12-029. The VGI RTP Pilot is targeted for rollout in 2024. In PG&E’s 2020 General Rate Case (GRC) Phase II, RTP rate pilots were approved for Residential, Commercial, and Industrial customers.
However, these pilots were designed to include only dynamic generation price components and would not meet the LMS requirements to include hourly distribution and transmission marginal cost signals. On September 25, 2023, PG&E filed a proposal – in support of the CPUC Energy Division Staff’s proposal in Track B of the CPUC’s DFOIR proceeding – to expand the VCE AgFIT Pilot (PG&E Expanded Pilots Proposal). With this proposed pilot expansion, all PG&E-customer classes – except Commercial Electric Vehicle (CEV) and Street Lighting – would be able to enroll in an RTP rate with dynamic generation and dynamic distribution cost components by June 2024. This implementation timing is dependent, however, on PG&E receiving CPUC approvals for these pilots by November 30, 2023. If the PG&E Expanded Pilots Proposal is adopted and implemented on the schedule proposed by the CPUC (June 2024), PG&E will meet the requirements of the LMS to have marginal cost-based hourly rates available to all customer classes (except for CEV) 41 6
for the generation and distribution components of the RTP rates well ahead of the Jan 2027 CEC target.
If PG&E’s proposal for including other customer classes (in addition to Agricultural) – as described in the PG&E Expanded Pilots Proposal – is adopted in the DFOIR proceeding, PG&E will be working with PG&E’s GRC II RTP Track settling parties to pause PG&E’s GRC II RTP pilot rates for the E-ELEC (Residential), B-6 (Small to Medium Commercial) and B-20 (Large Commercial and Industrial) rates. This will allow PG&E to replace those pilots with an RTP rate structure that includes not only marginal generation, but also marginal distribution cost components.
PG&E will provide an update on the plans to provide an LMS-compliant RTP rate for CEV customers by January 2027 in its next annual LMS Compliance Plan report.
Although the VGI Pilot Dynamic Rate includes dynamic generation and distribution, eligibility is limited – in order for CEV customers to enroll in phase 2 of that pilot, they must be interconnected under Rule 21. Interconnection under Rule 21 is required because the VGI Pilot’s objective is to encourage export to the grid and testing of vehicle-to-grid use cases. The VGI Pilot is a short-term pilot and is unlikely to be open to customers all the way to 2027. However, eligibility and a timeframe for the VGI dynamic rates could potentially be expanded to non-Rule 21 CEV customers.
Learnings from the Day-Ahead Real Time Pricing - Commercial Electric Vehicle (DAHRTP-CEV) opt-in rate, the CEV non-NEM export pilot – planned to launch in February 2024 – and the VGI Pilots Dynamic Rate targeted for Q3 2024 would be used to inform the design of the LMS-compliant RTP rate for CEV customers.6 PCE has participated in the proceeding developing these pilots and has expressed interest in participating in PG&E’s Expanded Pilots and BEV and VGI RTP pilots. Should PG&E receive approval from the CPUC to make the pilots LMS compliant, PCE will further evaluate engagement in the pilots as a means to achieve its own LMS goals, based on the details of the final implementation of these programs.
2.2.1. Rate Design
PG&E states the following regarding its plan for an LMS-compliant rate.
While still undergoing minor adjustments, PG&E’s currently preferred rate design will likely be similar to the rate design of its VGI RTP Pilot and will satisfy all but one of the LMS requirements – hourly transmission costs. The VGI RTP Pilot rate design includes marginal energy costs, marginal generation capacity costs, and marginal distribution capacity costs, but does not include hourly transmission costs ... While 6 Pacific Gas and Electric Company, 2023 LMS Compliance Plan (2023). 42 7
the VGI RTP Pilot rate design does not include marginal transmission capacity costs, PG&E is developing a roadmap toward an LMS-compliant rate in 2027.7 PG&E has outlined the details of its RTP rate and proposed the following for inclusion. • Frequency. Individual hourly prices updated on a day-ahead basis. • Marginal Capacity Costs. Marginal generation capacity costs as approved in D.21- 11-016 and allocation as specified in D.22-08-002.
• Marginal Energy Costs. Marginal energy costs as approved in D.21-11-016. These “are the CAISO energy prices at the PG&E Default Load Aggregation Point (DLAP), adjusted for line losses.”
8 • Marginal Transmission and Distribution Costs. Dynamic distribution signal created “to recover the Primary Distribution Capacity Costs approved in CPUC D.21- 11-016. The hourly prices will vary depending on the location of the customer and will utilize the scarcity pricing concept, with prices dependent on the forecasted load on a representative circuit with similar load characteristics to the customer’s circuit. As described in the Joint IOU WG 1 Proposal, hourly distribution prices will be set so that average prices are the same across all locations – prices on more constrained circuits will have more time differentiation, but annual average load-weighted prices will not vary geographically for equity reasons.” 9 • Fixed Costs. Fixed cost collection subscription mechanism as outlined in the California Flexible Unified Signal for Energy (CalFUSE) proposal, with no scalers or adders to denote the collection.
As previously stated, PCE will explore whether to adopt similar rates if PG&E implements an RTP rate in the future.
2.3. Evaluation
2.3.1. Cost-Effectiveness
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-effectiveness of any MCB rate offering depends on whether the value of any load shift to the customer and PCE exceeds the costs of implementation of the proposal.
Since CCAs are excluded from cost recovery for expenditures in support of wider grid benefits, the analysis of cost-effectiveness is necessarily narrower than it would be for either IOUs or POUs.
7 Id.
8 Id.
9 Id.
43 8
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 staff 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. • Contractor costs to implement MCB rates, including customer education and support.
• Software and upload costs associated with the MIDAS database interface.
In addition, per-customer costs include, but are not limited to:
• Data charges
• Vendor charges
At this time, the costs associated with the creation, implementation, and maintenance of the MCB rates are difficult to ascertain because many elements are still unknown. 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. However, for comparison, the Sacramento Municipal Utility District (SMUD) anticipates these fixed costs would be larger than the value of the marginal improvement in load over existing time-of-use (TOU) rates.10 Since PCE would be spreading comparable fixed costs across a customer base that is approximately a fifth the size of SMUD’s customer base, it is far less likely that the value of the marginal improvement in load shifting over PCE’s existing TOU rates would be enough to justify these fixed costs. PCE’s comparable fixed costs would be recovered from a smaller rate base, resulting in higher per-customer costs.
By the same token that the costs of implementation are difficult to determine, the value of any load shift that might result from an MCB rate is also difficult 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 differ from existing TOU rates in each of these hours.
Currently, several components of the marginal costs would be difficult to ascertain at this time. While hourly energy costs are currently generated in the CAISO market, the hourly 10 Sacramento Municipal Utility District, Sacramento Municipal Utility District Comments - SMUD's Load Management Standard (LMS) Compliance Plan (Attachment A) (2023). 44 9
capacity values are unclear. The resource adequacy (RA) program is shifting to a 24-hour slice-of-day framework, which would theoretically generate differential values of capacity in different 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 different 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 difficult or meaningless to calculate.
Determining the net value of any load shift would also require offsetting the cost of serving new load in the hour to which electricity use is shifted. This in turn would require an 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-effectiveness assessment is currently difficult or infeasible.
Given the difficulties in evaluating the cost-effectiveness of an MCB rate today, PCE is interested in participating in CPUC-sponsored IOU pilots. Such pilot programs with robust participation from all customer classes could provide some data on the sensitivity of electricity use to MCB rates. This is one contributing factor to PCE’s interest in participating in PG&E’s rate pilots to generate such information.
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 offering is likely to be primarily by wealthier and more sophisticated customers able to afford 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 difficult 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 cost 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 45 10
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 difficult to ascertain with reliable 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 differential value of capacity in different 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 Load Serving Entities 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 hourly data on a time basis. This likely requires CPUC action to order PG&E to provide such data to PCE.
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 the MCB rate is 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 46 11
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 the 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 sufficient 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 difficult to conceive of how this might be 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 electric vehicle (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 difficult 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 differentials are greater or less than the hourly differences in marginal costs. In theory, if the difference between high-rate hours and low-rate hours is less than the hourly differences 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 from 47 12
and to which hours. 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 (RIN)
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 RINs on the customer billing statements.
However, PCE is working with its third-party provider for data 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, just like it is with the design and placement of the RINs on the customer billing statements. PCE and other stakeholders are currently waiting for PG&E to propose a timeline for the development of the Statewide RIN Access Tool.
4. Load Flexibility Programs
4.1. Overview
Load flexibility and grid reliability are key elements of PCE’s decarbonization strategy. PCE has multiple offerings currently and is exploring a number of additional leading-edge options for its customers. Currently, these programs appear likely to play a central role in PCE’s load-shifting strategy to meet the objective of the LMS, especially if participation in the RTP pilots proves unworkable.
48 13
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,
11 use of low-power charging in multi-family
buildings, and fleet infrastructure planning.
12 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 effective 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 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.
4.1.1. Electric Vehicle Managed Charging
Overview: PCE 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 affect 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 11 Blake Herrschaft, Design Guidelines for Home Electrification, 7-12 (2023), https://www.peninsulacleanenergy.com/wp-content/uploads/2023/04/Design-guidelines-for-home-electrification-v041223.pdf 12 San Carlos Case Study: EV chargers for your fleet, less is more, Peninsula Clean Energy, https://www.peninsulacleanenergy.com/san-carlos-case-study-ev-chargers-for-your-fleet-less-is-more/; Access to slow EV chargers could speed up EV adoption among renters, Canary Media, https://www.canarymedia.com/articles/ev-charging/access-to-slow-ev-chargers-could-speed-up-ev-adoption-among-renters 49 14
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.
Status: PCE recently completed its second phase pilot of managed charging. The first phase was a proof of concept executed in 2020 with 7 vehicles. The proof of concept successfully demonstrated curtailment of charging at peak while ensuring drivers received the charging necessary for their daily needs. Following a competitive solicitation, PCE launched its second-phase pilot demonstrating scaled operation of EV-managed charging.
PCE selected EV.energy as its partner and engaged researchers at UC Davis to develop an experimental design to evaluate incentive structures and assess outcomes. About 700 vehicles participated in the second-phase pilot. Data collection has been completed and analysis is underway. PCE anticipates finalizing its ongoing program design and ramping up its recruitment in the coming months. Incentives to sign up are offered to EV purchasers through PCE’s income-qualified used EV incentive in addition to direct marketing to customers.
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. Initial 12 systems with 1.7 MW of solar are now completing construction.
13 The second round of the program is in contracting. The initial installations are the solar portion, and storage is intended to be added to select sites. 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. 13 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 50 15
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.14 With the state’s adoption of the Net Billing Tariff, 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. Under the agreement with the provider, the provider offers 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 cost energy efficiency 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 efficiency 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.
14 Q4 2023 PG&E Interconnection Data for Peninsula Clean Energy service territory 51 16
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 efficient 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.
15 Finally, PCE has also piloted an advanced load-shaping technology in space and water heating combo systems which can shift load in both applications through the thermal storage and advanced system logic. 16 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 off-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. 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). 15 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
16 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 52 17
The timeline and feasibility of the rollout of these technologies will be evaluated in future development of these programs.
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-Effectiveness
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 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 53 18
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 offerings 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 effective 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 (ex: backup vs. grid services) and interest in 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 offers 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. 54 19
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, different 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 difficulty 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 difficult 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-effective and technically feasible manner. Although load-flexibility technologies have many technical 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.
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.
55 DATE: April 16, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Shawn Marshall, Chief Executive Officer
SUBJECT: Approval of A Three-Year Contract with Robert Half & Associates for Temporary Staffing and Recruitment Support
Item No. 3
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Authorize the CEO to execute a three-year contract ending June 30, 2027 with Robert Half & Associates for temporary staffing and recruitment support on an as-needed basis.
BACKGROUND
In the summer of 2023 customer demand for program rebates and zero percent loans rapidly increased, thus creating additional administrative burden on staff and resultant processing delays. After researching various temp and staffing agencies in the area and soliciting recommendations, staff reached out to Robert Half & Associates to procure temporary administrative support for the programs team. Several months later, Robert Half & Associates also helped with temporary HR support and finding a qualified customer service/call center consultant. All placements for PCE have been high-quality candidates that have served our needs well. Candidates are fully vetted through background checks and are also bonded through Robert Half.
DISCUSSION
As PCE continues to expand its programs and the Agency grows its operational capabilities, we may need to occasionally draw on outside temporary staffing and recruitment support.
Staff is recommending continuing its relationship with Robert Half & Associate on a non-exclusive, as needed basis. The attached contract documents include a master services contract for a term ending June 30, 2027, a scope of work, and rate tables for various roles.
There is also an attachment that includes conversion rates in the event that PCE ultimately hires a temporary staffer provided by Robert Half.
FISCAL IMPACT
Not to exceed $250,000 in a fiscal year for temporary staffing and recruitment support, with a total NTE of $750,000 over the three year term. Hourly rates and costs of individual engagements will vary by scope and fee structure.
56 ATTACHMENTS:
Peninsula Clean Energy_RHCA_Multiple LOB_San Mateo, CA_04.17.24.pdf 57 RESOLUTION NO. _____________
PENINSULA CLEAN ENERGY AUTHORITY, COUNTY OF SAN MATEO, STATE OF
CALIFORNIA
APPROVAL OF A THREE-YEAR CONTRACT WITH ROBERT HALF & ASSOCIATES FOR
TEMPORARY STAFFING AND RECRUITMENT SUPPORT
RESOLVED, by the Peninsula Clean Energy Authority of the County of San Mateo, State of California, that
WHEREAS, Peninsula Clean Energy (PCE) was formed on February 29, 2016; and WHEREAS, PCE periodically needs to make use of temporary staffing and recruiting services to support its operations across various departments; and WHEREAS, in the summer of 2023, PCE began using the staffing support services of Robert Half & Associates, the costs for which are approaching the $100,000 threshold for Board approval; and
WHEREAS, PCE will contract with Robert Half & Associates to provide temporary staffing and recruitment support on a non exclusive, as-needed basis for a period of three years ending in June 2027 with a not to exceed cost cap of $750,000 over the term of the contract.
NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board delegates authority to the Chief Executive Officer to execute a contract with Robert Half & Associates for a term of three years and a not-to-exceed cost cap of $750,000 to support temporary staffing and recruitment support for PCE on an as-needed basis. 58 ©Robert Half Inc., 2024. All rights reserved. Robert Half Inc. is an Equal Opportunity Employer M/F/D/V 1 of 4
RH Customer Agreement
This RH Customer Agreement (the "Agreement") governs transactions by which you retain the services of Robert Half Inc., doing business through its finance & accounting contract talent, administrative & customer support, technology, marketing & creative, and management resources practice groups ("RH"), to assist Peninsula Clean Energy ("you" or "your") in meeting its contract talent needs.
Part 1 - General
1.1 Definitions
"Professional" means the individual assigned to you by RH. "Branch" means the RH branch located at the address identified under the Robert Half Inc. signature line of this Agreement.
"Services" means the provision of services by the Professional to you.
1.2 Agreement Structure
Additional terms for the Services are included in Exhibit A, which are attached to this Agreement. RH also provides additional terms for Services in documents called "job arrangement letters" which are also part of this Agreement. All transactions under this Agreement will have a job arrangement letter, which will be sent to you when RH provides Services to you. In order to initiate Services, you will provide RH with notice (e.g., via telephone, e-mail, facsimile, or mail) describing the Services you need in reasonable detail. RH will promptly reply to such request and indicate whether RH will or will not provide the requested Services. If RH elects to provide the requested Services, RH will send you a job arrangement letter.
If there is a conflict among the terms in the various documents, those of this Agreement prevail over those of a job arrangement letter. You accept the terms in a job arrangement letter by your approval of the Professional's weekly timesheet or electronic time record.
Services become subject to this Agreement when RH accepts your order by 1) sending you a job arrangement letter, or 2) providing the Services.
1.3 Charges and Payment
Amounts are due and payable as RH specifies in Exhibit A, including the fees payable for directly hiring Professionals and the fees payable if a Professional works overtime, e.g., in excess of 40 hours per week. You agree to pay accordingly, including any late payment fee.
1.4 Changes to the Agreement Terms
For a change to be valid, both parties must sign it. Additional or different terms in any written communication from you (such as a purchase order) are void.
1.5 Limitation of Liability
Circumstances may arise where, because of a default on RH's part or other liability, you are entitled to recover damages from RH. Regardless of the basis on which you are entitled to claim damages from RH (including fundamental breach, negligence, misrepresentation, or other contract or tort claim), RH's liability, if any, will (in the aggregate for all claims, causes of action or damages) be limited to any actual direct damages up to an amount equal to the fees actually paid to RH for the Services that are the subject of the claim. It is understood that you are responsible for implementing and maintaining usual, customary and appropriate internal accounting procedures and controls, internal controls and other appropriate procedures and controls (including information technology, proprietary information, creative designs and trade secret safeguards) for your company and RH shall not be responsible for any losses, liabilities or claims arising from the lack of such controls or procedures.
Items for Which RH is Not Liable
Under no circumstances is RH liable for any special, incidental, exemplary, indirect, lost profits, or consequential damages (including, but not limited to, lost business, revenue, goodwill, or anticipated savings), even if informed of the possibility.
1.6 General Principles of Our Relationship
a. Each party will maintain workers' compensation insurance and commercial liability insurance. b. RH will be responsible, to the extent applicable, for any workers' compensation insurance, federal, state and local withholding and unemployment taxes, social security, state disability insurance or other payroll charges for the Professionals.
c. In the event that any provision of this Agreement is held to be invalid or unenforceable, the remaining provisions of this Agreement remain in full force and effect.
1.7 Agreement Term
This Agreement will continue for a period of three years after the last date listed below, unless terminated earlier.
Either party may terminate this Agreement on thirty days' written notice to the other. Either party may terminate this Agreement if the other does not comply with any of its terms, provided the one who is not complying is given written 59 ©Robert Half Inc., 2024. All rights reserved. Robert Half Inc. is an Equal Opportunity Employer M/F/D/V 2 of 4
notice and reasonable time to comply. Any terms of this Agreement which by their nature extend beyond the Agreement termination remain in effect until fulfilled, including the payment obligations set forth in Section 1.3 above, and apply to each party's respective successors and assignees.
1.8 Warranties
EXCEPT AS SET FORTH IN EXHIBIT A, RH MAKES NO EXPRESS OR IMPLIED WARRANTIES REGARDING THE
SERVICES, INCLUDING, BUT NOT LIMITED TO, ANY WARRANTY OF QUALITY, PERFORMANCE, MERCHANTABILITY OR FITNESS FOR ANY PURPOSE.
Part 2 - Services
2.1 Pre-Assignment Screening
If you require RH to perform background checks or other placement screenings of Professionals, you agree to notify RH prior to the start of services under this Agreement. RH will conduct such checks or screenings only if they are described in a signed, written amendment to this Agreement. If you request a copy of the results of any checks conducted on RH's Professionals, you agree to keep such results strictly confidential and to use such results in accordance with applicable laws and solely for employment purposes.
2.2 Scope of Assignment
You shall supervise Professionals providing services to you. You shall not permit or require Professionals (i) to perform services outside of the scope of Professional's assignment; (ii) to sign contracts or statements (including SEC documents); (iii) to make any management decisions; (iv) to use computers, or other electronic devices, software or network equipment owned or licensed by Professional; or (v) to make any final decisions regarding system design, software development or the acquisition of hardware or software.
2.3 Cash Handling and Other Financial Transactions and Activities If you permit or allow a Professional to sign, endorse, wire, transport or otherwise convey cash, securities, checks, or any negotiable instruments or valuables, or conduct financial transactions or other related activities, you accept sole responsibility for all claims, demands and liability that may arise from permitting these activities. You represent and warrant that to the extent you permit or allow a Professional to engage in the activities described in this paragraph, you will not permit or allow a Professional to handle more than (i) $1,000 per day if you are a non-profit entity, or (ii) $25,000 per day if you are a for-profit entity. Since RH is not a professional accounting firm, you agree that you will not permit or require Professional (a) to render an opinion on behalf of RH or on your behalf regarding financial statements; (b) to sign the name of RH on any document; or (c) to sign their own names on financial statements or tax returns.
2.4 Workplace Safety
It is understood that you have full responsibility for: (i) providing safe working conditions as required by law, including compliance with all public health and occupational safety regulations and guidelines applicable to your business, and (ii) ensuring that safety plans exist for, and safety related training is provided to, Professionals working on your premises. To ensure the safety of potentially vulnerable individuals on your premises, you agree not to permit the Professionals to have unsupervised or unmonitored contact with (a) minors or (b) adults who are under your care, custody or supervision because of mental health impairments. If any assignment under this Agreement is for work to be performed under a government contract or subcontract, you will notify RH immediately (1) of any obligations in the government contract or subcontract relating to wages, and (2) if RH is legally required to initiate E-Verify verification procedures for any Professional. RH reserves the right to re-assign any Professional.
2.5 Operation of Vehicle and Equipment
RH does not authorize Professionals to operate machinery (other than office machines) or vehicles. If you wish to permit Professionals to drive for business purposes, you accept sole responsibility for all liability, damages, injuries or other claims that may arise or be incurred as a result of such driving. If you require Professionals to drive a vehicle owned by you or your employee, you agree to maintain such vehicle in good working condition and maintain all necessary and appropriate insurance for the operation of such vehicle. Under no circumstances will you permit Professionals to: (i) make bank deposits, (ii) carry cash in excess of $100, negotiable instruments or other valuables while driving, or (iii) carry passengers in the vehicle. It is agreed that you accept full responsibility for, and that RH does not maintain insurance to cover any injury, damage, or loss that may result from your failure to comply with the foregoing.
2.6 Remote Work
you may request that RH permit its Professionals to provide services to you remotely (i.e., from a location other than your or your customer's premises) using your or RH's laptop and/or other computer or telecommunications equipment (the “Equipment”). You acknowledge and agree that RH shall have no control over, and you shall be solely responsible for, (i) the logical and physical performance, reliability and security of the Equipment or related devices, network accessibility and availability, software, services, tools and e-mail accounts (collectively, “Computer Systems”) used by the Professional, and (ii) the security, integrity, and backing up of the data and other information stored therein or transmitted thereby. Moreover, you must not permit Professional to save or store any of your files or other data on the Computer Systems provided by RH (including, but not limited to, any virtual desktop infrastructure solution). You agree that RH shall not be liable for any loss, damage, expense, harm, business interruption or inconvenience resulting from the use of such Computer Systems. 60 ©Robert Half Inc., 2024. All rights reserved. Robert Half Inc. is an Equal Opportunity Employer M/F/D/V 3 of 4
2.7 Claims
RH will not be responsible for any claim related to the engagement, including, but not limited to, any Services performed during such engagement, unless you reported such claim in writing to RH within ninety (90) days after termination of the applicable assignment.
2.8 Confidentiality
The Professionals will execute any confidentiality agreement that you may require. You agree to be responsible for obtaining the Professional's signature. You agree to hold in confidence the identity of any Professional and the Professional's resume, social security number and other legally protected personal information, and you agree to implement and maintain reasonable security procedures and practices to protect such information from unauthorized access, use, modification or disclosure.
This Agreement is only applicable to, and the only Robert Half branch and practice groups obligated under this Agreement are, the finance & accounting contract talent, administrative & customer support, technology, marketing & creative, and management resources practice groups of the Branch. This Agreement and its job arrangement letter(s) are the complete agreement regarding these transactions and replace any prior oral or written communications between the Branch and you regarding these transactions.
By signing below, both parties agree to the terms of this Agreement. Once signed, 1) any reproduction of this Agreement or job arrangement letter(s) made by reliable means (for example, photocopy or facsimile) is considered an original and 2) all Services ordered under this Agreement are subject to it.
Agreed to:
Peninsula Clean Energy
By______________________________
Authorized Signature
Name (type or print):
Date:
Customer address: 2075 Woodside Rd., Redwood
City, CA 94061
Agreed to:
Robert Half Inc.
By______________________________
Authorized Signature
Name (type or print):
Date:
Branch address: 919 E Hillsdale Blvd., Suite 275,
Foster City, CA 94404
After signing, please return a copy of This Agreement to the RH "Branch address" shown above. 61 ©Robert Half Inc., 2024. All rights reserved. Robert Half Inc. is an Equal Opportunity Employer M/F/D/V 4 of 4
Exhibit A
Professionals are assigned to you under the following additional terms:
1. Guarantee - RH guarantees your satisfaction with the Services of the Professional by extending to you (i) a one-day (8 hours) guarantee for placements made through the finance & accounting or administrative & customer support practice group, (ii) a two-day (16 hours) guarantee for placements made through the management resources or marketing & creative practice group or (iii) a five-day (40 hours) guarantee for placements made through the technology practice group (the "Guarantee Period"). If, for any reason, the Professional is not satisfactory to you, RH will not charge for the hours worked during the Guarantee Period, provided that you allow RH to replace the Professional. Unless RH is contacted by you before the end of the Guarantee Period, you agree that the Professional is satisfactory for the purposes of this guarantee.
2. Bill Rates and Time Sheet - Hourly rates for all assignments will be agreed on a case-by-case basis. For specified positions, below, the hourly rate will be within the range identified. Professional will present a time sheet or an electronic time record to you for verification and approval at the end of each week. RH will bill you weekly for the total hours worked; RH's invoices are due upon receipt, including applicable sales and service taxes all of which are payable by you. In the event that RH’s invoices are not paid by you when due, you agree to pay all of RH’s costs of collection, including reasonable attorneys' fees, whether or not legal action is initiated. Additionally, RH may, at RH’s option, charge interest on any overdue amounts at a rate of the lesser of 1½% per month or the highest rate allowed by applicable law from the date the amount first became due. RH may charge you a fee for the provision of equipment or technology, if you request that Professional use equipment or technology provided by RH. RH may also increase RH’s rates to reflect increases in RH’s cost of doing business, including costs associated with higher wages for workers and/or related taxes, benefits or other costs. RH will provide written or verbal notice of technology charges and/or increases in rates. Any increase in rates will be prospective, starting as of the effective date RH specifies.
Functional Roles Bill Rate Per Hour
Receptionist and Front Desk $40 - $48
Data Entry $38 - $50
General Office (Filing Scanning) $36 - $45
Administrative Assistant $45 - $72
Executive Assistant $85 - $105
Customer Service $42- $55
Office Manager $72 - $90
HR Admin $50 - $70
Accounting Clerk $ 44 - $52
Accounts Receivable / Accounts Payable Specialist $52 - $71 Staff Accountant $74 - $84
Entry-Level Financial Analyst (0-2 years) $56 - $65
Payroll Specialist $75 - $90
Senior Accountant $120 - $140
Payroll Manager $130 - $150
Accounting Manager $140 - $160
Asst Controller $160 - $180
Controller $180 - $200
Senior Financial Analyst $120 - $140
Finance Manager $140 - $160
Finance Director $160 - $180
Developer / Engineer $109 - $150
Desktop Support Analyst $56 - $75
Project Manager/Sr. Consultant $134 - $151
Systems Security Administrator $106 - $145
62 ©Robert Half Inc., 2024. All rights reserved. Robert Half Inc. is an Equal Opportunity Employer M/F/D/V 5 of 4
Database Administrator $106 - $135
Graphic Designer $70 - $81
Copywriter $88 - $93
Production Artist $67 - $70
User Experience (UX) Designer $114 - $130
Digital Marketing Specialist $61 - $71
HR Coordinator $55 - $70
HR Generalist $75 - $85
Sr. HR Generalist: $90 - $110
HR Manager $110 - $125
HR Business Partner $115 - $145
HR Director $130 - $150
Benefits Coordinator $65-$80
Benefits Analyst $85 - $95
Benefits Manager $95 - $125
HRIS Analyst $95 -$125
HRIS Manager $125 - $160
3. Overtime - If applicable, overtime will be billed at 1.50 times the normal billing rate. Federal law defines overtime as hours in excess of 40 hours per week, state laws vary. If state law requires double time pay, the double time hours will be billed at 2.00 times the normal billing rate.
4. Hiring the Professional - After you evaluate the performance and potential of a Professional on the job, you may wish to employ this person directly. In such event, you agree to pay a conversion fee. The conversion fee is payable if you hire the Professional, regardless of the employment classification, on either a full-time, temporary (including temporary assignments through another agency) or consulting basis within twelve months after the last day of the assignment. You also agree to pay a conversion fee if the Professional is hired by (i) a subsidiary or other related company or business as a result of your referral of the Professional to that company or (ii) one of your customers as a result of the Professional providing services to that customer.
The conversion fee will be owed and invoiced upon your hiring of the Professional, and payment is due upon receipt of the invoice. The same calculation will be used if you convert the Professional on a part-time basis using the full-time equivalent salary.
The conversion fee will equal a percentage of the Professional's aggregate annual compensation, including bonuses, based on the length of assignment:
Hours Billed and Paid Conversion Fee
0 – 160 hours 35%
161– 320 hours 30%
321 – 480 hours 25%
481 – 640 hours 20%
641 – 800 hours 15%
801 – 960 hours 10%
961 hours or more +5%
63 DATE: March 25, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Rafael Reyes, Senior Director of Energy Programs
SUBJECT: Approval of Contract Amendment with David Fribush to increase the contract amount by $260,000 and to extend the term of the Agreement to December 31, 2026
Item No. 4
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Authorize the Chief Executive Officer to Execute an Amendment to the Agreement with David Fribush to increase the contract amount by $260,000 and to extend the term of the Agreement to December 31, 2026.
BACKGROUND
In May 2020, Peninsula Clean Energy and David Fribush executed an agreement to provide Distributed Energy Resource (DER) strategy and program execution services. The contract was authorized through December 2024, and this most recent request is to extend the term to December 31, 2026 and provide an additional contract amount of $260,000 for a total not-to-exceed amount of $785,000 covering the entire 6.5 year contract period.
Mr. Fribush has played an integral role supporting PCE's Solar and Storage on Public Buildings program (“GovPV”). GovPV is in the construction phase for Round 1 with 12 sites, and in contracting phase for the larger Round 2 of the program. Mr. Fribush has served an instrumental role in research, financial modeling and project management support, especially for Round 1. In addition, he has managed key startup portions of the “Green Access” program (also known as the Disadvantaged Community – Green Tariff program) which provides 20% bill discounts to income-qualified customers.
DISCUSSION
PCE has hired additional staff to support the GovPV program with the new Associate Programs Manager, Ross Fisher, joining in March. Mr. Fisher will assume direct project management of GovPV construction administration and operations so that Mr. Fribush can redirect his time and talents to serving the next phase of PCE's GovPV program.
The next major phase of the program will be to add battery storage as part of the offering.
Currently, three sites under construction in Round 1 have an interest in storage and a number 64 of additional sites were identified as candidates in Round 2. Mr. Fribush has specific expertise in battery systems and will be providing support on financial modeling, battery dispatch duty cycles, and other operating considerations.
Mr. Fribush has previously been offered the opportunity to join PCE in a full-time staff capacity and he has declined, preferring to remain an independent contractor. The subject contract amendment extends the term of his services to December 31, 2026.
FISCAL IMPACT
The fiscal impact of amending the agreement with Dave Fribush will not exceed $260,000 and will be within the existing Program Department budget forecast.
ATTACHMENTS:
2024.04.25 BOD Programs - Fribush Amendment - Amnt 6.docx 65 RESOLUTION NO. _____________
PENINSULA CLEAN ENERGY AUTHORITY, COUNTY OF SAN MATEO, STATE OF
CALIFORNIA
APPROVAL OF CONTRACT AMENDMENT WITH DAVID FRIBUSH TO INCREASE THE CONTRACT AMOUNT BY $260,000 AND TO EXTEND THE TERM OF THE AGREEMENT TO DECEMBER 31, 2026
RESOLVED, by the Peninsula Clean Energy Authority of the County of San Mateo, State of California, that
WHEREAS, the Peninsula Clean Energy Authority (“Peninsula Clean Energy” or “PCE”) was formed on February 29, 2016; and
WHEREAS, in May 2020, Peninsula Clean Energy and David Fribush (“Contractor”) executed an agreement to provide distributed energy resource strategy and implementation services in an initial amount of $90,000 and subsequently amended with an increased term and amount up to $525,000; and
WHEREAS, PCE will require additional services and support solar and storage implementation and desires to extend the term of Contractor’s agreement to December 31, 2026; and
WHEREAS, PCE’s total obligation to Contractor in the proposed amended agreement shall not exceed $785,000; and
WHEREAS, Contractor has unique capabilities to provide solar and storage support to Peninsula Clean Energy;
WHEREAS, staff is presenting to the Board for its review an amendment to the Agreement, reference to which should be made for further particulars; and WHEREAS, the Board wishes to delegate to the Chief Executive Officer authority to execute the aforementioned amendment to the Agreement.
NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board delegates authority to the Chief Executive Officer to finalize and execute the sixth amendment to the Agreement with the Contractor Dave Fribush for a total amount not to exceed with terms consistent with those presented, in a form approved by the General Counsel. 66 Peninsula Clean Energy Contract Amendment Template 01/17/20 (JSK) AMENDMENT NO. 6 TO AGREEMENT BETWEEN PENINSULA CLEAN ENERGY
AND DAVID FRIBUSH
THIS AMENDMENT TO THE AGREEMENT, entered into this __1_ day of __May_, 2024_ by and between PENINUSLA CLEAN ENERGY, a California joint powers authority, hereinafter called "PCE," and David Fribush, hereinafter called "Contractor"; W I T N E S S E T H:
WHEREAS, the parties entered into an Agreement on May 29, 2020 for the purpose of Contractor’s distributed energy resources strategy and execution (“Agreement”); and WHEREAS, the parties wish to amend the Agreement to extend the term of the Agreement.
NOW, THEREFORE, IT IS HEREBY AGREED BY THE PARTIES HERETO AS FOLLOWS:
1. The sentence addressing term in Section 3 shall be removed and replaced with the following:
“Subject to compliance with all terms and conditions, the term of this Agreement shall be from June 1, 2020 through December 31, 2026.”
2. The text of Section 2 “Payments” shall be amended to replace “[i]n no event shall PCEA’s fiscal obligation under this Agreement exceed three hundred seventy-five thousand dollars ($525,000)” with the following:
“In no event shall PCEA’s fiscal obligation under this Agreement exceed seven hundred eighty-five thousand dollars ($785,000).”
3. Except as expressly amended herein, all other provisions of the Agreement shall remain in full force and effect.
4. This Amendment No. 6 shall take effect upon the date of mutual execution by both parties.
IN WITNESS WHEREOF, the parties hereto have executed this Amendment as set forth below.
Peninsula Clean Energy Authority
67 Peninsula Clean Energy Contract Amendment Template 01/17/20 (JSK) By: _______________________
Shawn Marshall, CEO
Dated: __________
______________________
By:
Name: David Fribush
Title: Technical Consultant / Contractor
Dated:
68 DATE: April 17, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Nicholas Bijur, Chief Financial Officer
SUBJECT: Approval of Renewal of Insurance Coverage for the Period from May 1, 2024, through May 1, 2025, at a cost of $197,787
Item No. 5
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Approval of renewal of insurance coverage for the period from May 1, 2024, through May 1, 2025, at a cost of $197,787.
BACKGROUND
Following a detailed review of Peninsula Clean Energy’s (PCE’s) exposures and requirements, PCE staff recommended and the Board adopted an expanded and enhanced insurance program in April 2019. The insurance program has since been renewed annually after being approved by the Board.
Most of PCE’s current insurance policies expire on May 1, 2024. PCE staff engaged its insurance broker, USI Insurance Services (USI), to seek competitive bids from the insurance marketplace. USI presented PCE with a comprehensive insurance package, which staff recommends for approval.
DISCUSSION
After several years of challenging market conditions and increasing premiums, the insurance market has generally improved. These favorable market conditions are offset in part by increased PCE revenue, expenditures, and headcount, which directly impacts pricing on several of PCE's policies. The proposed annual premium of $197,786 represents a 4% increase over last year at the same coverage limits. Below is a summary of the insurance coverage being renewed.
Public Officials Liability Policy – Coverage includes Directors & Officers (D&O), Employment Practices Liability, and Professional Liability. Coverage limits are $5 million for each claim and in the annual aggregate. The annual premium increased by 18% to $88,684 due the significant increase in PCE revenue, expenditures, and employee headcount.
Cyber – Coverage applies to claims relating to cyber-attacks, breach cost, and sub-69 limited coverage for social engineering claims. Coverage limits are $2 million policy aggregate and $500,000 for social engineering. The cyber insurance market has improved significantly after several years of increasing premiums, resulting in a 2% decrease in the annual premium to $62,609. Workers Compensation – Coverage applies to work-related injuries and Employers Liability. Employers Liability protects PCE from a third-party bringing a claim related to an injured employee. Coverage is guided by the State and limits are $1 million. The premium decreased 10% to $17,951 due to favorable market conditions.
General Liability – Coverage applies to claims from third-parties for property damage and/or bodily injury (i.e., slips and falls). Coverage limits are $1 million per occurrence and $2 million in the aggregate. The annual premium of $7,058 represents a 2% increase over last year.
Property – Coverage applies to business and personal property and provides business income and/or extra expense following a property loss. Despite very difficult property market conditions, the annual premium only increased 5% to $6,254.
Fiduciary – Coverage protects from claims of mismanagement and the legal liability related to serving as a fiduciary. Coverage limits are $1 million. The 26% increase in premium to $2,922 is largely driven by the increase in employee headcount.
Crime – Coverage applies to claims associated with employee dishonesty. Coverage also includes sub-limited coverage for social engineering claims. Coverage limits are $500,000. The 29% increase in premium to $2,502 is largely driven by the increase in employee headcount.
Auto – Coverage applies to vehicles that are leased, rented or hired, and protects PCE from auto liability claims arising from employees driving their own vehicles on company business. Coverage limits are $1 million. PCE’s premium decreased by 32% to $510.
Umbrella – Coverage allies over primary limits on General Liability, Auto, and Employers Liability. Coverage limits are $10 million in excess of primary. The premium increased 8%.
In addition to the above-mentioned insurance coverage, PCE also has approximately $10 million of property coverage for the equipment being installed as part of the GovPV program which does not expire for another 8 months and is not being renewed at this time; the annual premium is approximately $21,000.
FISCAL IMPACT
The annual cost of the proposed insurance renewal is $197,787, an increase of $7,256, or 4%, over last year.
70 RESOLUTION NO. _____________
PENINSULA CLEAN ENERGY AUTHORITY, COUNTY OF SAN MATEO, STATE OF
CALIFORNIA
APPROVAL OF RENEWAL OF INSURANCE COVERAGE FOR THE PERIOD FROM MAY 1, 2024, THROUGH MAY 1, 2025, AT A COST OF $197,787
RESOLVED, by the Peninsula Clean Energy Authority of the County of San Mateo, State of California (“Peninsula Clean Energy” or “PCE”), that
WHEREAS, the Board of PCE reviewed and approved a revised and expanded insurance program at its meeting on April 25, 2019; and
WHEREAS, the policies in the current insurance program were renewed by approval of the Board in April 2020, April 2021, April 2022, and April 2023; and WHEREAS, the policies in the current insurance program have an expiration date of May 1, 2024; and
WHEREAS, PCE staff engaged its insurance broker to seek competitive bids from the insurance marketplace; and
WHEREAS, PCE desires to continue its insurance policies and coverage, including Public Official and Management Liability, Cyber, Workers Compensation, General Liability, Property, Umbrella, Fiduciary Liability, Crime and Automobile coverage for the period of May 1, 2024 through May 1, 2025.
NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board approves the renewal of the insurance program for the period from May 1, 2024 through May 1, 2025 at an annual cost not to exceed $197,787.
71 DATE: April 15, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Phillip Kobernick, Senior Programs Manager, Transportation SUBJECT: Approval of One EV Ready Program Fund Reservation Agreement, Providing Approximately $185,000 in Customer Incentives
Item No. 6
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Approval of one Fund Reservation Agreement, which will provide an expected total of approximately $185,000 in customer incentives to install EV charging infrastructure at a condominium property in East Palo Alto, as part of the EV Ready Program.
BACKGROUND
In December 2018, the Board approved PCE’s EV charging infrastructure program intended to accelerate EV adoption in San Mateo County. The program, later named the “EV Ready Program,” provides incentives and no-cost technical assistance to eligible property types, which include: 1) Affordable Housing, 2) Multi-Unit Dwellings (such as apartments and condominiums), 3) Employee Charging, including fleet, and 4) All Publicly Accessible, Non-Residential Locations. The program provides incentives for several different EV charging types, as part of the programs “right-speeding” strategy to install cost-effective charging options, depending on the use case. These incentivized charging options include: 1) Level 1 or Level 2 outlets, 2) Level 2 EV charging stations, 3) Make-Ready parking spaces, to encourage future-proofing, and 4) panel updates for multi-family property sites. These incentives range from $1,000 to $5,500 per charger, depending on property type, retrofit vs new build projects, and charging type.
Customers apply for EV Ready incentives online, which is reviewed and approved by Peninsula Clean Energy staff. Once approved, a Fund Reservation Agreement, which outlines the EV Ready Program standards and requirements, is distributed via DocuSign and executed by the customer and the Peninsula Clean Energy CEO. Fund Reservation Agreements are presented to the Board of Directors prior to execution by the Peninsula Clean Energy CEO when individual Agreements are valued at $100,000 or more.
DISCUSSION
In the prior month, Peninsula Clean Energy received one EV Ready application in which the 72 Fund Reservation Agreement is expected to exceed $100,000 in incentives and is presented to the Board of Directors for approval.
Following approval by the Board of Directors, this project’s Fund Reservation Agreement will be executed by the Peninsula Clean Energy CEO and the customer will proceed to install their EV charging infrastructure and file for reimbursement from Peninsula Clean Energy upon completion in the future, subject to the EV Ready Programs Standards and Requirements.
Details of the Fund Reservation Agreement are included below. This incentive application is being submitted by a condominium property in East Palo Alto, which is planning to install 90 EV charging outlets, to provide EV charging access to all residents.
Property Type
Total Expected
Reserved Funds
Total Charge Ports
Expected City
Multi-Unit Dwelling $185,000 90 East Palo Alto
FISCAL IMPACT
Funding for this project is included the Board-approved EV Ready Program.
STRATEGIC PLAN
Goal 3 – Community Energy Programs:
Objective A: Develop market momentum for electric transportation Key Tactic 1: Drive personal electrified transportation to majority adoption Objective B: Deliver tangible benefits throughout our diverse communities Key Tactic: Expand charging access and equity to low income communities ATTACHMENTS:
Woodland Creek FRA_Rdctd.pdf
73 RESOLUTION NO. _____________
PENINSULA CLEAN ENERGY AUTHORITY, COUNTY OF SAN MATEO, STATE OF
CALIFORNIA
APPROVAL OF ONE EV READY PROGRAM FUND RESERVATION AGREEMENT, PROVIDING APPROXIMATELY $185,000 IN CUSTOMER INCENTIVES RESOLVED, by the Peninsula Clean Energy Authority of the County of San Mateo, State of California, that
WHEREAS, Peninsula Clean Energy was formed on February 29, 2016; and WHEREAS, expanding access to charging in increases adoption of electric vehicles to reduce greenhouse gasses is part of Peninsula Clean Energy’s program roadmap approved by the Board; and
WHEREAS, in December 2018, the Peninsula Clean Energy Board of Directors approved the EV charging infrastructure program, which came to be called the “EV Ready” program; and WHEREAS, eligible applicants are approved for EV Ready program incentives, subject to the EV Ready Program Standards & Requirements; and
WHEREAS, approved applicants in the EV Ready program are required to execute a Fund Reservation Agreement to secure their financial incentives; and WHEREAS, per Peninsula Clean Energy policy, Agreements valued at or above $100,000 require approval by the Peninsula Clean Energy Board of Directors; and WHEREAS, one EV Ready incentive application for a multi-unit dwelling property in East Palo Alto, whose Fund Reservation Agreement is expected to be valued at or above $100,000 in value was received by Peninsula Clean Energy in the prior month; and
WHEREAS, the Board wishes to delegate to the Chief Executive Officer authority to finalize and execute the Fund Reservation Agreement in the EV Ready program to provide incentives.
NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board delegates authority to the Chief Executive Officer to execute a customer Fund Reservation Agreement in the EV Ready program to provide incentives for an expected total of approximately $185,000 to a multi-unit dwelling property in East Palo Alto. 74 75
V 12.16.22
Designated Applicant Assignment form was completed and submitted to PCEA to verify that the Site Owner or Owner Representative has designated the applicant (“Designated Applicant”) authority to represent the Site Owner in the Program and execute all legal agreements as required by the Program.
The undersigned here is the: Site Owner or Owner Representative OR Designated Applicant [DocuSign]
Peninsula Clean Energy EV Ready Program Terms and Conditions
1. ELIGIBILITY: Peninsula Clean Energy Authority offers a rebate to eligible PCEA customers or their designees (Applicant) installing EV Charging Infrastructure through the EV Ready Program. Applicants eligible to receive rebates under the Program must (1) abide by the terms and conditions listed herein; (2) have the EV charging port(s) metered through a PCEA account number; (3) comply with Program Standards and Requirements (“Program Requirements”) in Appendix A; (4) provide PCEA with Required Installation Verification Documents as specified in the Program Requirements upon completion of the project.
2. REBATE RESERVATION TERM AND AMOUNT: The amounts of the rebates for which qualifying projects are eligible are outlined in Program Requirements. Rebate funds are reserved upon execution of this Agreement up to the maximum amount identified in the Program Requirements based on the “EV Charging Infrastructure Project Description” (hereinafter, the Project, see page 1 above). The funds are reserved according to the Fund Reservation Period timelines outlined in the Program Requirements and any modifications to the timelines are at the discretion of PCEA. Rebates will be paid to eligible Rebate Recipient once installation is verified as complete by PCEA. The final amount of the rebates will be the actual eligible costs of verified EV Charging Infrastructure installed or the maximum amount reserved, whichever is less.
3. DISCRETION ON VERIFICATION: Determinations regarding verification pursuant to paragraph (1) and paragraph (2) of these Terms and Conditions, shall be determined at PCEA’s complete and exclusive discretion.
4. REBATE RECIPIENT: The Applicant may direct the rebate funds to any Rebate Recipient, who is a single vendor or service provider incurring costs for the Project up to the amount of documented costs incurred by that Rebate Recipient. The Rebate Recipient shall be identified in the Installation Verification Form submitted upon project completion to request disbursement of the rebate.
5. NO GUARANTEES: PCEA makes no guarantee, representations or warranties, expressed or implied, regarding the implementation or use of EV Charging Infrastructure and equipment purchased or installed pursuant to this PCEA Program.
Customer is solely responsible for any liability, legal or otherwise, arising from the installation, operation, and maintenance of its selected EV Charging Infrastructure.
6. EVSE PACKAGE: Upon approval of the Funds Reservation Agreement by PCEA, for Level 2 EV Charging Ports, as defined in Appendix A, Program Requirements, the Customer shall select and procure EV Supply Equipment (EVSE), software, and network services as required and in compliance with the Equipment Requirements outlined in the Program Requirements.
Customer shall install, operate and maintain the number and type of the EVSE unit(s) (defined in Program Requirements), associated equipment, and signage as selected by Customer and approved by PCEA. Customer acknowledges that:
a. For all Level 2 EV charging port(s) included in the project, the Customer agrees to purchase a) a minimum 2-year software and networking service agreement and b) a maintenance contract or a 3-year warranty with the Electric Applicant Signature Date
Peninsula Clean Energy Representative Signature Title Date DocuSign Envelope ID: C916FCE9-B1E6-4DA2-9C37-4ABA4D7949C0 76 V 12.16.22
Vehicle Servicer Provider (EVSP) or Original Equipment Manufacturer (OEM) providing the EVSE to the Customer.
7. ADDITIONAL SERVICES FROM ELECTRIC VEHICLE SERVICE PROVIDER (EVSP): Separate and apart from the Funds Reservation Agreement and PCEA’s obligations under the Program, the EVSP may offer and contract directly with the Customer to provide any additional or complementary services, as long as these services do not interfere with the objectives of the Program. PCEA is not responsible for the costs of additional EVSP services or any cost related to operations and maintenance of any additional EVSP services.
8. INSTALLATION OF EV CHARGING INFRASTRUCTURE: Customer is responsible for covering all upfront costs of the installation of the EV Charging Infrastructure. Upon completion of installation of the EV Charging Infrastructure, Site Owner understands it is responsible for the operation and maintenance of the EV charging port(s) installed.
9. CONTRACTOR REQUIREMENTS: All work performed on projects under this agreement shall be done by contractors who hold a valid California C-10 license. PCEA reserves the right to amend and change contractor requirements at any point during the program.
10. EV DRIVERS RIGHT TO ACCESS: Customer may limit the availability of the EV Charging Infrastructure to its employees or tenants. Under the Program, Customer may elect to make the EV Charging Infrastructure available for use by the general public. Customer shall not restrict access to use of the EV Charging Infrastructure for reasons including, but not limited to, race, color, religion, age, sex, national origin, ancestry, physical or mental disability, or any basis prohibited by applicable law.
11. APPLICABLE LAWS: Customer is solely responsible for ensuring that the EV Charging Infrastructure is installed and operated in compliance with all applicable local, state, and federal laws.
12. EV CHARGING PORT(S) OPERATION AND MAINTENANCE: Customer will pay all ongoing costs associated with the EV Charging Infrastructure. Customer shall maintain a consistent uptime for the EV Charging Port(s) installed. Customer shall maintain the common area immediately surrounding the EV Charging Infrastructure in good condition, ordinary wear and tear accepted, and will promptly notify PCEA of any problems it is aware of related to the EV Charging Infrastructure. Such maintenance by Customer of the immediately surrounding common areas shall include, but not be limited to, pavement maintenance. Customer shall promptly notify PCEA if Customer will no longer maintain the installed EV Charging Infrastructure and/or the installed EV Charging Infrastructure is being removed from Customer’s site. Uninterrupted service is not guaranteed, and Pacific Gas & Electric (PG&E) may interrupt service and access to the EV Charging Infrastructure when necessary to ensure safety or to perform maintenance as dictated by utility easement agreements and requirements.
13. PERMISSION TO USE DATA: For all EV Charging Infrastructure installed that are capable of collecting and reporting usage and utilization data, Site Owner agrees to allow PCEA and its authorized Contractors to access, collect, use, and report EV Charging Infrastructure usage and utilization data gathered as a part of the Program for use in regulatory reporting, ordinary business use, industry forums, case studies, or other similar activities, in accordance with applicable laws and regulations.
PCEA and its authorized Contractors shall have access to the EV Charging Infrastructure usage and utilization data indefinitely and in accordance with all applicable laws, including but not limited to PCEA privacy guidelines and relevant regulatory decisions.
14. DEMAND RESPONSE and LOAD SHAPING PROGRAMS: Customer agrees that PCEA may, at its discretion enroll all networked EV charging port(s) units installed under the Program in any future demand response, grid optimization, and/ or load shaping programs implemented by PCEA. Future load shaping program will, by design, not incur any additional costs or expenses to Customer. The load shaping program will aim to curtail energy usage for each charging port during a predefined period established by PCEA. These curtailments will be designed to minimally impact EV drivers that are charging during these times whenever possible. Customers will be provided an appropriate mechanism to opt-out before the program is implemented.
15. TAX LIABILITY and CREDITS: PCEA is not responsible for any taxes which may be imposed on Customer as a result of the rebates provided within the Program. Site Owners receiving incentives from either the Program and/or other regional organizations, including, but not limited to, the Bay Area Air Quality Management District, that have been facilitated through assistance from PCEA are required to designate their Low Carbon Fuel Standard (LCFS) credits to PCEA. Customer attests they are releasing their rights to report and claim credits in the LCFS and are designating credits in the LCFS to PCEA DocuSign Envelope ID: C916FCE9-B1E6-4DA2-9C37-4ABA4D7949C0 77 V 12.16.22
(FEIN 81-2708786) on an ongoing basis. Customer will inform third-party entities when necessary, including CARB, that the LCFS credits generated by their installed EVSE are designated to PCEA on an ongoing basis. Customer will provide the EVSE usage and electricity data to PCEA for LCFS reporting pursuant to CARB sections 95483.2(b)(8), 95491 and 95491.1.
Customer will provide PCEA with ongoing access to EV charging data through the use of a login to the online account and/or an application program interface (API), a dashboard with exportable data files, or other means to access the charging data.
16. DISPUTES: Except where otherwise limited by law, PCEA reserves the right, at its sole discretion, to make final determinations regarding any disputed issues about the Program, including but not limited to eligibility and rebate amounts. In the event of a dispute that cannot be remedied by the parties, any court filings and/or proceedings shall be venued in San Mateo County, California. PCEA shall in no case be responsible for the legal costs of Site Owner and/or Designated Applicant.
17. PROGRAM CHANGES: PCEA reserves the right to change, modify, or terminate the Program at any time without any liability except as expressly stated herein. PCEA will honor all written commitments made in the Funds Reservation Agreement provided to Customers prior to the date of any change, modification or termination of this program, provided that project installations are fully completed within the timeframe specified within the Program Requirements.
18. PROGRAM EXPIRATION: The Program will expire upon the earliest to occur: (i) December 31st, 2024, (ii) when funds are depleted, or (iii) when the program is terminated by PCEA.
19. INDEMNIFICATION: Applicant agrees to indemnify, defend, and hold PCEA, its employees, officers, and agents, harmless from any and all liabilities including, but not limited to, litigation costs and attorney's fees arising from any and all claims and losses to anyone who may be injured or damaged by reason of Customer's negligence, recklessness or willful misconduct while participating in the PCEA Program.
20. ACKNOWLEDGEMENTS: Customer shall acknowledge PCEA as a funding source of the installed EV Charging Infrastructure each time Customer’s activities related to the EV Charging Infrastructure are published in any news media, press release, brochures, or other type of public communication or promotional material. The acknowledgement of PCEA’s support as a funding source, whether in whole or in part, shall include language such as: “Funding for [Customer Site Name]’s charging station(s) provided by Peninsula Clean Energy.” If Customer is receiving funding from multiple organizations, Customer may use one statement conforming to the format listed above and include all organizations from which funding is received.
PCEA also reverses the right to install stickers, signage, or other advertisement mechanism on the EV charging port(s) funded or facilitated by PCEA.
21. CUSTOMER DISCLOSURE AUTHORIZATION: By signing the Funds Reservation Agreement, Applicant confirms they are the authorized representative for the electric account holder identified in the Funds Reservation Agreement and authorized PCEA to disclose Customer’s account status and participation in the PCEA Program. If Applicant is not the authorized representative for the electric account holder identified in the Funds Reservation Agreement, the Applicant certifies that they have submitted a Third Party Designated Applicant Assignment Form to verify that the Site Owner has delegated authority to the Applicant to represent the Site Owner and execute the Funds Reservation Agreement.
DocuSign Envelope ID: C916FCE9-B1E6-4DA2-9C37-4ABA4D7949C0 78 DATE: April 24, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Nelly Wogberg, Board Clerk
SUBJECT: Approval of Minutes from the October 26, 2023 and February 22, 2024 Board of Directors Meetings
Item No. 7
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Approve Minutes from the October 26, 2023 and February 22, 2024 Board of Directors Meetings
ATTACHMENTS:
10-26-2023 BOD Draft Minutes.docx
02-22-2024 BOD Draft Minutes.docx
79 Regular Meeting of the Board of Directors of the
Peninsula Clean Energy Authority (PCEA)
Minutes
Thursday, October 26, 2023
6:30 p.m.
Zoom Video Conference and Teleconference
CALL TO ORDER
Meeting was called to order at 6:36 p.m. in virtual teleconference, in the Peninsula Clean Energy Authority lobby, and in the Los Banos City Hall conference room A.
ROLL CALL
Participating:
Rick DeGolia, Atherton, Chair
Julia Mates, Belmont
Coleen Mackin, Brisbane
Donna Colson, Burlingame, Vice Chair
Carlos Romero, East Palo Alto
Sam Hindi, Foster City
Leslie Ragsdale, Hillsborough, participating remotely under AB 2449 Paul Llanez Faria, Los Banos, joined at 6:44 p.m.
Betsy Nash, Menlo Park
Anders Fung, Millbrae, joined at 6:42 p.m.
Tygarjas Bigstyck, Pacifica
Craig Taylor, Portola Valley
Kaia Eakin, Redwood City
Marty Medina, San Bruno
John Dugan, San Carlos
Adam Loraine, San Mateo
James Coleman, South San Francisco
Kevin Bryant, Woodside
Absent:
Dave Pine, San Mateo County
Ray Mueller, San Mateo County
Ken Gonzalez, Colma
Roderick Daus-Magbual, Daly City
Harvey Rarback, Half Moon Bay
A quorum was established.
PUBLIC COMMENT
David Mauro
80 ACTION TO SET THE AGENDA AND APPROVE REMAINING CONSENT AGENDA ITEMS Public Comment: David Mauro
Phillip Kobernick, Senior Programs Manager for Transportation provided an update on the status of the projects included in Agenda Item Number 1.
Chair DeGolia asked if this item was coming to the Board tonight because it was assumed the CEO could approve these, but because they are contractual, they needed to come before the Board. Phillip explained that almost 100 projects under the 100k amount have been approved, but that there was some confusion on if projects under a main project that has been approved needs to be brought to the Board.
MOTION: Director Mates moved, seconded by Director Hindi to set the Agenda, and approve Agenda Item Numbers 1-4.
1. Approval of 19 EV Ready Program Fund Reservation Agreements, Providing $2,634,000 in Customer Incentives.
2. Approve Revised Policy #19 - Investment Policy.
3. Approve the Audited Financial Statements for Fiscal Year 2022-2023.
4. Approve Cash Management and Investment Management Structure.
MOTION PASSED: 23-0 (Absent: San Mateo County, San Mateo County, Colma, Daly City, Half Moon Bay)
JURISDICTION BOARD MEMBER YES NO ABSTAIN ABSENT
San Mateo County Director Pine X
San Mateo County Director Mueller X
Atherton Director DeGolia X
Belmont Director Mates X
Brisbane Director Mackin X
Burlingame Director Colson X
Colma Director Gonzalez X
Daly City Director Daus-Magbual X
East Palo Alto Director Romero X
Foster City Director Hindi X
Half Moon Bay Director Rarback X
Hillsborough Director Ragsdale X
Los Banos Director Llanez X
Menlo Park Director Nash X
Millbrae Director Fung X
Pacifica Director Bigstyck X
Portola Valley Director Taylor X
Redwood City Director Eakin X
San Bruno Director Medina X
81 San Carlos Director Dugan X
San Mateo Director Loraine X
South San Francisco Director Coleman X
Woodside Director Bryant X
Total 18 5
REGULAR AGENDA
5. Chair Report
None
6. CEO Report
Shawn Marshall, Chief Executive Officer, gave a presentation including an update on the Surplus Funds Committee, Peninsula Clean Energy National Support, information on the November Board Retreat, an update on automation and IT, and a staffing update.
Marc Hershman, Director of Government Affairs, provided a legislative update.
7. Community Advisory Committee Report
Cheryl Schaff, Community Advisory Committee (CAC) Chair, gave a report on the October 12, 2023 CAC meeting.
8. Approval of Solar Billing Plan Program
Leslie Brown, Director of Account Services, gave a presentation on the Solar Billing Plan Program including background information, Peninsula Clean Energy’s Solar Billing Plan (SBP) policy, the annual cash out on SBP, alterations from PG&E’s SBP, policy considerations, and key takeaways.
Chair DeGolia asked if under the new system, would customers pay the retail rate for energy used and get the reduced rate for energy generated. Leslie explained that what is generated from solar is used first in the home. When the kWh leaves the house and goes to the grid, you wont get a retail credit but instead an Energy Export Credit (EEC). Chair DeGolia asked if the purpose was to encourage battery backup and to discharge the batteries during the peak hours. Leslie confirmed the goal is to encourage people to use the energy you generate at home, store it in a battery, or export solar during peak time.
Director Eakin asked for clarification on solar homeowners. Leslie explained that nothing will change for solar customers who have an active solar connection agreement, and that this program applies to those who submitted an interconnection agreement after April 15, 2023 or have older systems that require an updated interconnection agreement.
Director Eakin asked for clarification that this is less of a good deal than it used to be. Leslie explained that yes, this program is less generous than the Net Energy Metering (NEM) 2.0 program. Director Eakin asked if it makes sense for Peninsula Clean Energy to keep the value high for solar users.
Leslie explained that Peninsula Clean Energy only controls a small portion of the charges on a customer’s bill, and that new solar users will be subject to larger portions of the bill from state rules 82 and policy from the investor-owned utilities which will apply to a large portion of their bill. If Peninsula Clean Energy did nothing to our side of the bill, the increase would be insignificant to the overall value of the system. Shawn Marshall, Chief Executive Officer, added that the impact would be negligible and would increase customer confusion.
Director Taylor asked if Peninsula Clean Energy had considered adding batteries. Leslie explained that is being discussed internally, such as ways to incentivize offsetting usage. Director Taylor any way of measuring the potential negative impact due to the additional cost of the batteries. Leslie explained that there was a large influx of interconnection applications before the April deadline, and that installers are now trying to deliver on the systems sold in the months before the new rules went into effect.
Chair DeGolia noted that there are still 2.5 years left to complete installation of systems under NEM
2.0. Chair DeGolia asked about the addition of $.01 to the energy export credit and if it would give our customers who generate more power from solar panels than they consume over 12 months a $.01 benefit for their excess power. Leslie explained that it is a $.01 adder to the net surplus compensation rate, which is the calculation that happens at the end of the 12 months.
Chair DeGolia stated that we could add a penny to energy export credit. Leslie explained it would be very expensive, but that we that cannot model it because Peninsula Clean Energy does not yet get this data from customers or PG&E.
MOTION: Vice Chair Colson moved, seconded by Director Medina to approve the proposed Solar Billing Plan (SBP) program policy.
MOTION PASSED: 23-0 (Absent: San Mateo County, San Mateo County, Colma, Daly City, Half Moon Bay)
JURISDICTION BOARD MEMBER YES NO ABSTAIN ABSENT
San Mateo County Director Pine X
San Mateo County Director Mueller X
Atherton Director DeGolia X
Belmont Director Mates X
Brisbane Director Mackin X
Burlingame Director Colson X
Colma Director Gonzalez X
Daly City Director Daus-Magbual X
East Palo Alto Director Romero X
Foster City Director Hindi X
Half Moon Bay Director Rarback X
Hillsborough Director Ragsdale X
Los Banos Director Llanez X
Menlo Park Director Nash X
Millbrae Director Fung X
Pacifica Director Bigstyck X
Portola Valley Director Taylor X
83 Redwood City Director Eakin X
San Bruno Director Medina X
San Carlos Director Dugan X
San Mateo Director Loraine X
South San Francisco Director Coleman X
Woodside Director Bryant X
Total 18 5
9. Update on Diversity, Equity, Accessibility, and Inclusion (DEAI) Action Plan Implementation Kirsten Andrews Schwind, Senior Manager of Community Relations, gave a presentation including action plan development, organizational culture and DEAI commitment, including specific department responsibilities, and implementation challenges.
Director Hindi asked about the annual staff training and if the plan was outlined through the consultant, GCAP. Kirsten explained that the outline was developed through GCAP, but that Staff is still determining who the provider will be. Shawn Marshall, Chief Executive Officer, added that the media types will alo be varied.
10.Annual Strategic Plan Update
Shawn Marshall, Chief Executive Officer, introduced the Annual Strategic Plan update including a recap of adjustments since September 2022, and Organizational Priorities.
Andy Stern, Interim Chief Financial Officer, gave a presentation of the Financial Stewardship Annual Strategic Plan update.
Director Mackin asked about the stewardship update and difference from the 2023 Year to Date and 2025 Target decrease in Cost of Energy. Andy explained that the 2025 target was made when the Strategic Plan was created with the hope to stabilize the average cost of energy, but that has proven challenging as energy costs have gone up, noting that this is not a projection of future costs of energy but rather a measurement against a long-term target.
Roy Xu, Director of Power Resources, gave a presentation of the Power Resources Annual Strategic Plan update.
Vice Chair Colson asked about the staff collaboration when analyzing Power Purchase Agreements and if the process is becoming more robust. Roy explained that evaluating incoming project proposals has not changed, but the back-office staffing helps to manage projects as they are coming online and to manage contract terms.
Phillip Kobernick, Programs Manager, gave a presentation of the Community Energy Programs Annual Strategic Plan update.
Director Loraine asked about power outages in San Mateo County. Phillip explained that there haven’t been major PSPS events, but during the storm season outages occurred for multiple days.
Gwen Rose, Director of Marketing and Community Relations, gave a presentation of the Marking and Community Outreach Annual Strategic Plan update.
84 Director Mackin asked about the participation rate and if there should be a goal to increase that goal.
Leslie Brown, Director of Account Services, explained that the rate hovers around 97% as there is an ebb and flow of customers opting out and enrolling, and that to do a re-enrollment campaign, there are challenges and would reflect a mostly residential campaign.
Director Taylor asked about Peninsula Clean Energy’s favorability. Gwen explained that there is not unfavorable, but rather not enough information to be favorable, and that a very small percentage are actively unfavorable, mostly stemming from misperceptions.
Director Nash asked if there is a place to have community events listed on the website. Gwen explained that this is in progress.
Leslie Brown, Director of Account Services, gave a presentation of the Account Services Annual Strategic Plan update.
Director Mackin asked about the timely uploads of gas data within DataConnect. Leslie explained that the DataConnect portal allows customers to extract all their data in one stream, and that the gas data also allows customers to pull data for home upgrade electrification. Director Mackin asked if this would be available to residential customers. Leslie explained that it was built as an interface for vendors but that it is technically available to residential customers.
Chair DeGolia asked about the CalTrain electrification plan. Leslie explained that CalTrain is ready to go live in the Fall of 2024. Chair DeGolia asked about the power up stations. Leslie explained that there is one station in San Mateo County and one in San Jose, and that power mixes are being considered.
Jeremy Waen, Director of Public Policy, and Marc Hershman, Director of Government Affairs, gave a presentation of the Public Policy Annual Strategic Plan update.
Shawn Marshall noted that there has been internal discussions about the fostering Community Choice Aggregators (CCAs) Growth Key Performance Indicator, noting that there hasn’t been much interest within Merced County on expansion, the market is challenging, and suggests pushing back the goal a few years until the market improves.
Director Mackin asked if hydrogen had any part in this and about local political pushback from other regions. Shawn explained she wasn’t sure about hydrogen and that there isn’t pushback from Merced, but rather no response.
Director Fung asked about the economics of the acquisition of new customers. Shawn explained that with some analysis of bringing on new customers and growth that requires new power supply, there is not a lot of head room to absorb the new customer base. She explained with the economic issue combined with a lack of general interest, it makes sense to not push hard at the moment and wait for things to improve.
Director Fung commented on the margin between wholesale and retail as not worth pursuing. Roy explained that if a new city were added, Peninsula Clean Energy’s peak load would increase, and the Resource Adequacy (RA) requirement would increase, where we would need to purchase more RA in a high cost environment. This cost would balance across all ratepayers in the territory. 85 Shawn Marshall, Chief Executive Officer, gave a presentation of the Organizational Excellence Annual Strategic Plan update.
11.Regulatory Update Pending 2024 Rate Changes
Jeremy Waen, Director of Regulatory Policy, gave a presentation on the regulatory update pending the 2024 rate changes from PG&E including the 2024 Energy Resource Recovery Account (ERRA) Forecast overview and outlook, the PG&E 2023 General Rate Case (GRC) Phase 1 overview, consideration of the Income-Graduated Fixed Charge (IGFC), and timing for commission action.
12.Board Members’ Reports
Director Bigstyck noted an interview with Senator Josh Becker available on the Half Moon Bay website.
Director Coleman shared a South San Francisco Council of Cities event Saturday, October 28 at 5:30pm.
ADJOURNMENT
Meeting was adjourned at 9:25 p.m.
86 Regular Meeting of the Board of Directors of the
Peninsula Clean Energy Authority (PCEA)
Minutes
Thursday, February 22, 2024
6:30 p.m.
Zoom Video Conference and Teleconference
CALL TO ORDER
Meeting was called to order at 6:35 p.m. in virtual teleconference, in the Peninsula Clean Energy Authority lobby and in the Los Banos City Hall conference room A.
SWEARING IN OF NEW BOARD MEMBER
David Silberman, General Counsel, presided over the swearing-in ceremony of new Board Member, Tom McCune from Belmont.
ROLL CALL
Participating:
Dave Pine, San Mateo County
Rick DeGolia, Atherton, Chair
Tom McCune, Belmont
Coleen Mackin, Brisbane
Ken Gonzalez, Colma
Roderick Daus-Magbual, Daly City
Carlos Romero, East Palo Alto
Sam Hindi, Foster City
Harvey Rarback, Half Moon Bay
Leslie Ragsdale, Hillsborough
Betsy Nash, Menlo Park
Anders Fung, Millbrae, arrived at 7:16 p.m.
Tygarjas Bigstyck, Pacifica
Craig Taylor, Portola Valley
Elmer Martinez Saballos, Redwood City
Marty Medina, San Bruno
John Dugan, San Carlos
Adam Loraine, San Mateo
James Coleman, South San Francisco
Absent:
Ray Mueller, San Mateo County
Donna Colson, Burlingame, Vice Chair
Paul Llanez, Los Banos
Ned Fluet, Woodside
A quorum was established.
87 PUBLIC COMMENT
None
ACTION TO SET THE AGENDA AND APPROVE REMAINING CONSENT AGENDA ITEMS Chair DeGolia announced some confusion with the timing of Agenda Item Number 8 and requested that the item be pulled from the Agenda until the March 28, 2024 Board meeting.
Nelly Wogberg, Board Clerk, announced that only the minutes from the January 25, 2024 Board meeting need to be approved and the other two were added inadvertently.
MOTION: Director Rarback moved, seconded by Director Hindi to set the Agenda, and approve Agenda Item Numbers 1-2.
1. Approval of Minutes from the May 25, 2023, June 22, 2023, and January 25, 2024 Board Meetings.
2. Joint Powers Authority Agreement Weighted Voting Shares Allocation.
MOTION PASSED: 18-0 (Absent: San Mateo County, Burlingame, Los Banos, Millbrae, South San Francisco)
JURISDICTION BOARD MEMBER YES NO ABSTAIN ABSENT
San Mateo County Director Pine X
San Mateo County Director Mueller X
Atherton Director DeGolia X
Belmont Director McCune X
Brisbane Director Mackin X
Burlingame Director Colson X
Colma Director Gonzalez X
Daly City Director Daus-Magbual X
East Palo Alto Director Romero X
Foster City Director Hindi X
Half Moon Bay Director Rarback X
Hillsborough Director Ragsdale X
Los Banos Director Llanez X
Menlo Park Director Nash X
Millbrae Director Fung X
Pacifica Director Bigstyck X
Portola Valley Director Taylor X
Redwood City Director Martinez Saballos X
San Bruno Director Medina X
San Carlos Director Dugan X
San Mateo Director Loraine X
South San Francisco Director Coleman X
Woodside Director Fluet X
Total 18 5
88 REGULAR AGENDA
3. Chair Report
None
4. CEO Report
Shawn Marshall, Chief Executive Officer, gave a presentation including feedback on the Peninsula Clean Energy rate freeze, an update on meeting minutes, upcoming points of interest, a recap of the CalCCA Lobby Day on February 21, 2023, and a staffing update.
Director Daus-Magbual suggested including Senator Scott Wiener and Assemblymember Phil Ting in future meetings as they represent parts of San Mateo County.
Marc Hershman, Director of Government Affairs, provided a legislative update.
Director Hindi asked if there was any feedback on rate increases from legislators. Shawn shared that plans of how to deal with rates was not shared.
Director Dugan asked about Peninsula Clean Energy’s relationship with the California Public Utilities Commission (CPUS). Shawn explained that we have a good relationship with the CPUC. Chair DeGolia added that we meet with Commissioners annually and touch base throughout the year on shifting issues.
5. Community Advisory Committee Report
Cheryl Schaff, Community Advisory Committee (CAC) Chair, gave a report on the February 8, 2024 CAC meeting.
6. Three-year Contract with Franklin Energy in an Amount Not-to-Exceed $26,000,000 for the Implementation of a Turnkey Electrification Installation Service for Single-family Homes (Action) Alejandra Posada, Programs Manager for Building Electrification Programs, gave a presentation including background on building electrification goals and progress, a timeline for Building Electrification V2, details on the Request for Proposals (RFP) for turnkey installation services, details on Franklin Energy and Team, and budget details.
Director Nash asked for clarification on what is counted. Alejandra explained that these are projects that Peninsula Clean Energy has supported.
Director Romero asked to confirm that all dryers installed are Heat Pump. Alejandra explained that electric resistance dryers are being installed as well. Director Romero noted that there is an energy savings with heat pump dryers that could make sense with savings on the bill side.
Director Taylor asked when the whole house would be scaled considering the backlog of single appliances. Alejandra explained that it would happen immediately. Director Taylor asked if the funds would run out before completing whole homes. Alejandra explained that the program is structured to 89 support at a minimum 575 whole homes. Director Taylor asked if the concierge is broad enough to include batteries at the customer’s house? Alejandra confirmed.
Director Dugan asked if the sliding scale is on a cost share basis or fully free and if this would be for low-income households? Alejandra explained that it would be offered completely free to residents and that it would be for home-owners with less than 80% of the average median income for homeowners. Director Dugan asked if a sliding scale was considered. Alejandra explained that this was considered but noted that as this program scales, creating a more sliding scale would be considered. Shawn Marshall, Chief Executive Officer, added that the only piece that is entirely on Peninsula Clean Energy is the lower income customer as other income levels would be on a sliding scale.
Director Dugan asked if the waitlist would be prioritized on income levels? Alejandra explained that the waitlist has not yet been income qualified, noting that in the past, the programs have been first come, first serve.
Director Dugan asked if anyone would be allowed to do market rate purchases. Alejandra confirmed that market rate purchases, but that as a function of budget, 2000 homes wouldn’t be possible. Rafael Reyes, Director of Energy Programs, added that there will still be 2 options: someone who wants to DIY and wants the rebate or on-bill financing and someone who wants to be guided through the whole process. He noted that in the long-run, scaling the project and tiering the program across all the segments that are served will be needed.
Director Dugan suggested a top tier that is cost-neutral for Peninsula Clean Energy but provides a high level of service. Rafael explained there have been discussion of offering on-bill finance, but not rebates, and that the team would be returning to the Board with other concepts. Shawn added that revenue diversification strategies, such as a congressional earmark, could assist in covering that.
Director Gonzalez asked where building permits come in with concierge service. Alejandra explained that this is part of the scope with Franklin; contractors doing the installation would handle plans, permits, and compliance.
Director Taylor asked if the cost is lowest to go through Franklin than through a random contractor.
Alejandra explained that the program will pay prevailing wage and may not be the lowest cost and that there will be fixed pricing, minus rebates. Director Taylor asked if there would be volume discounts on the equipment. Alejandra explained that Franklin will work with a distributor and that discounts are factored into the program, adding that the contract could be amended in the future if better pricing opportunities are available.
Director Bigstyck asked if Franklin would register with the Department of Industrial Relations (DIR) with a prevailing wage projects number. Alejandra explained Franklin doesn’t intend to do prevalilg wage verification through DIR, but that the contractors are the ones who are enrolled and doing the installation work and being paid prevailing wage.
Director Taylor asked what services are assumed for whole-home electrification. Alejandra explained that the $26 million breakdown includes $2 million in funds from Menlo Park due to a grant they received from the California Energy Commission and will be focused on low-income qualified installs, and added that the budget assumes every home gets every single electric appliance upgrade, which will likely not be the case in practice.
90 Director Mackin asked for clarification on light energy efficiency repairs. Alejandra explained that window replacements are not part of this, but added installation, air ceilings, LED lightbulbs and smart thermostats would be included. Rafael Reyes added there is an analysis of the service territory and believe that the majority of homes in the service territory are 100 or 200 amp panels, and that there will be a cost threshold, so older homes with knob and tube may not be able to be served.
Director Taylor for clarification on the number of market-rate installs. Alejandra explained that 175 are estimated, but if more are needed, the team would return to the Board with an amendment Director Taylor asked if there is any cost to them to get them to do the site assessment and some of the work? Alejandra explained there is no cost for the site assessment, noting that before installation occurs, they would need to sign a binding agreement.
Director Loraine asked about the increase in reach throughout the member agency with this program.
Rafael explained that there is no estimate of how many customers will want to use the turnkey service, noting that some contractors are doing direct to customer marketing and as a consequence, anticipate that the volume may be modest. Noting that a scaling goal would be an easy pathway for customers and that if many contracts are doing this, that will make it as easy for customers.
Director Mackin suggested offering the assessment at cost as a comfort benefit to customers.
Director Nash asked if the contact center would be available to everyone and if support would be available in multiple languages. Alejandra confirmed, and explained that the major languages in the county will be included. Director Nash asked about trust within the community. Alejandra explained that Peninsula Clean Energy intends to engage directly with our Community Based Organizations which are already doing underground work on enrolling homes into programs like these.
Director Nash asked about a contract with the homeowner requiring they don’t sell the home within a certain period of time. Alejandra explained the participation agreement will be developed once the contract is signed.
Director Ragsdale asked about the types of homes that can be included. Alejandra explained that the contract will cover up to 4 dwelling units.
Director Taylor asked if the CEO has any ability to switch funding amounts between categories.
Alejandra explained that yes, there is the ability to move funds between budget lines.
Director McCune asked if an assessment of operating costs will be used to provide accuracy.
Alejandra explained that Xero-Home is an energy modeling software that Franklin will use during the site assessments for each individual home. Rafael shared that information has been published but hasn’t been presented to the Board, Blake Herschaft and members of the SVCE team, spent a lot of time on operating costs. The determination was that generally under the E-ELEC rate there are modest savings with electrification.
Director Mackin asked if renters have been considered. Alejandra explained that this would cover rental occupied units and tenant occupied units. The income qualified piece is not planned to support renters as the long-term benefit supports the property owners.
Public Comment: None
91 MOTION: Director Nash moved, seconded by Director Romero to Delegate authority to the CEO to execute a 3-year contract with Franklin Energy for the implementation of the turnkey electrification installation service for single-family homes.
MOTION PASSED: 19-0 (Absent: San Mateo County, Burlingame, Los Banos, South San Francisco)
JURISDICTION BOARD MEMBER YES NO ABSTAIN ABSENT
San Mateo County Director Pine X
San Mateo County Director Mueller X
Atherton Director DeGolia X
Belmont Director McCune X
Brisbane Director Mackin X
Burlingame Director Colson X
Colma Director Gonzalez X
Daly City Director Daus-Magbual X
East Palo Alto Director Romero X
Foster City Director Hindi X
Half Moon Bay Director Rarback X
Hillsborough Director Ragsdale X
Los Banos Director Llanez X
Menlo Park Director Nash X
Millbrae Director Fung X
Pacifica Director Bigstyck X
Portola Valley Director Taylor X
Redwood City Director Martinez Saballos X
San Bruno Director Medina X
San Carlos Director Dugan X
San Mateo Director Loraine X
South San Francisco Director Coleman X
Woodside Director Fluet X
Total 19 4
7. Study Session on Project Ownership (Discussion)
Roy Xu, Director of Power Resources, gave a presentation including utility ownership through large centralized projects and local/distributed projects, Peninsula Clean Energy ownership considerations, pros and cons to ownership, a comparison to ownership versus long-term contracts, and some ownership cases.
Director Fung asked how many megawatts long-duration storage would produce. Roy explained around 70-80 megawatts. Director Fung asked what that is in terms of load. Roy explained that our Peak load is 700 megawatts, with too much excess solar in our portfolio right now, noting the need for batteries.
Director Loraine asked if this conversation was had at the formation of Peninsula Clean Energy and what may have changed to bring this conversation back. Chair DeGolia explained that this conversation did not occur because Peninsula Clean Energy did not have any money, and that the 92 financial situation has changed, noting credit possibilities that didn’t exist before. Roy added that the Inflation Reduction Act benefit is also a game-changer.
Director Pine asked if other CCAs have moved in the area of ownership. Roy explained that MCE has MCE Solar 1 that has a PPA option which has not been executed yet.
Director Dugan asked how durable our purchases would be. Roy explained that it varies; a solar project would need replacement in 20-25 years whereas a large hydro project can run for many years.
Director Mackin asked for clarification on joint ownership. Roy explained that this would be a joint ownership with buyers such as Investor-Owned Utilities (IOUs), other Community Choice Aggregators (CCAs). Roy explained that if everyone commits to the project, through economies of scale a larger project could be purchased.
Director Dugan asked how the extended value gets calculated. Roy explained that the large-scale projects have large-scale residual extended value, but for solar and wind a degradation calculation can be done to determine the extended value. Director Dugan clarified land in proximity to grid could become a scarce resource. Roy explained that site control and land costs is a piece of energy project development, and that if we purchased land that could become an investment, but noted we would have to think if we are in the business of buying land.
Chair DeGolia asked about virtual power plants. Rafael Reyes, Director of Energy Programs, explained that the residential solar and storage program with SunRun does continue to provide virtual power plants dispatch and that as the government solar program moves toward storage, dispatch in a coordinated manner will be looked at as well.
Director Mackin asked if Case #4 could be a partnership with different buildings and utilizing their sites to set up a similar program to GovPV with property owners. Rafael explained that in the near-term there is a plan to return with a distributed energy resources plan for residential solar and storage, Gov PV, and other residential assets, including virtual power plant control over thermostats. Rafael added that there are complexities into moving into the commercial sector.
Public Comment: None
8. Selection of Board of Directors Chair and Vice Chair to be Effective March 2024 (Action) This item was continued to March 28, 2024.
9. Board Members’ Reports
Chair DeGolia shared that Atherton approved a fee structure that stated that all permits, if they are identified as green, would not have a cost.
ADJOURNMENT
Meeting was adjourned at 9:11 p.m.
93 DATE: March 15, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: None
TO: Honorable Peninsula Clean Energy Authority Executive Committee FROM: Shawn Marshall, Chief Executive Officer
SUBJECT: CEO Report (Discussion)
Item No. 9
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
BACKGROUND
This report is provided monthly to the Board of Directors and is informational only.
DISCUSSION
During the Board meeting, Shawn Marshall, CEO will provide an update on a variety of PCE topics including but not limited to:
April 2024 Legislative Update
Every three years, the California Department of Housing and Community Development (HCD) develops and adopts new building codes. One proposed change this year caught the eye of Peninsula Clean Energy’s Programs Team. The proposed code, if enacted as drafted, would have eliminated the opportunity for our EV Ready program to install Level 1 EV charging at apartment and condominium buildings.
Peninsula Clean Energy has been an advocate for the installation of Level 1 charging as a proven solution for EV charging installation. It is not only cost-effective, but it can be installed quickly and is not subject to delays experienced by projects facing lengthy connection timelines.
Peninsula Clean Energy reached out to legislators, other CCAs, and non-governmental organizations to enlist their support of language that would allow the installation of Level 1 chargers in an existing multi-family building, regardless of quantity or scope.
We want to extend our sincere appreciation to Senator Josh Becker (D-Menlo Park), Senator Henry Stern (D-Simi Valley), Assemblymember Marc Berman (D-Palo Alto), and Assemblymember Chris Ward (D-San Diego) who sent a strong letter of support to HCD, as did the California Electric Transportation Coalition and 11 CCAs through a letter submitted by CalCCA.
In response to our efforts, the HCD’s own advisory committee voted 8-1 to adopt our 94 suggested language that would allow for the installation of Level 1 charges in multi-family buildings.
This is not a final determination, and the process going forward is a bit opaque. We continue to work with our legislators and other supporters to encourage HCD staff to incorporate this language into their next public-facing proposal.
I would also like to call your attention to 3 bills for which we have taken a support position:
1. SB 1095 from Senator Becker. This bill updates code ambiguities to ensure individuals can switch from gas to electric appliances. It prevents HOAs from implementing provisions that would stop the switching, clarifies the authority of individuals to replace gas with electric appliances in mobile and manufactured homes, and provides the Department of Housing and Community with the authority it needs to update its regulations should there be legal uncertainty that would inhibit appliance replacement.
SB 1095 was passed by two policy committees, the Senate Committee on Housing and the committee on the Judiciary. It now awaits action by the Senate Committee on Appropriations where it has been placed on the suspense calendar.
2. SB 1130 from Senator Bradford. This bill would require the PUC to review a report from each IOU to ensure the IOU has sufficiently enrolled eligible households in the FERA program. The PUC will be charged with verifying that the proportion of households the commission determines to be eligible within the electrical corporation’s service territory is enrolled in the program. If the commission, in its review of a report, determines an IOU has not sufficiently enrolled eligible households in the FERA program, the commission would require the IOU to develop a strategy and plan to sufficiently enroll eligible households. SB 1130 passed the Senate Committee on Energy, Utilities, and Communications. It also now awaits action by the Senate Committee on Appropriations where it has been placed on the suspense calendar.
3. Since the preparation of the legislative matrix attached to your agenda, we have also taken a support position on AB 2815 from Assemblymember Petrie-Norris. AB 2815 would require the California Energy Commission to establish a program to provide grants for repairs to EV charging infrastructure that has been in operation for at least 5 years and that is in a publicly available parking space. The bill would authorize grant funding to be used for the cost to repair or replace an EV charging station. The bill would require the commission to allocate at least 50% of grant funding to low-income communities and disadvantaged communities. This legislation passed the Assembly Committee on Transportation and is now referred to the Committee on Natural Resources.
PCE's EV Ready Program Wins Community Impact Award at CalCCA CalCCA has awarded PCE's EV Ready Program as a Community Impact Award winner in the Decarbonization Category, in a ceremony headed by CEC Commissioner David Hochschild at the annual conference in San Jose. The EV Ready program was recognized for its use of scalable and cost-effective low-power EV charging solutions, leading customers to nearly triple the size of their EV charging projects on average, and success in deploying charging into multi-family properties, a historically underserved community. Over 1,000 chargers have already been installed with nearly 4,000 more in progress. Congrats to our great team for making this happen!
PCE in the Community
Staff has been busy getting the word out and sharing their expertise. PCE speaking 95 engagements will be shared during the meeting.
Staff and Community Advisory Committee members have enjoyed connecting with our customers at the many Earth Day and other spring events this month. We thank our member agencies and community partners for inviting us to participate and engage with our customers. We hope to see you at one of these events! 4/2/2024 Home Electrification Workshop in San Mateo
4/5/2024 Nueva School Staff Health & Wellness Fair
4/13/2024 Love Our Earth Festival (East Palo Alto and Menlo Park) 4/14/2024 South San Franscisco Earth Day
4/18/2024 Gilead Earth Day Event
4/20/2024 SMC Progress Seminar
4/20/2024 Pacific Beach Coalition EcoFest
4/20/2024 Belmont Earth Day
4/20/2024 Los Banos Spring Street Faire
4/21/2024 Atherton Earth Day
4/23/2024 Oracle Earth Day
4/26/2024 South San Francisco High School Assembly
4/27/2024 Foster City Earth Day
4/27/2024 Children's Day, Dia del Nino in San Bruno
4/30/2024 San Mateo County Sustainable Schools Summit
5/5/2024 Peninsula Temple Sholom Presentation
5/5/2024 Cinco de Mayo Festival in East Palo Alto
5/8/2024 Burlingame Library Electrification Workshop
5/18/2024 Los Banos Home Fair 2024
5/23/2024 Pacheco High School Wax Museum
PCE Staffing Update
Please welcome to our team:
Kelly Lew-Quintal, Risk Manager, who started on April 16th Posted Positions - PCE is hiring! Please help us spread the word.
Data Engineer/Analyst, Data and Technology
Analyst/Senior Analyst, Building Electrification Support Senior Manager, Strategic Analysis and Rates, Finance and Administration 96 DATE: April 12, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Donna Colson, Chair of the Board
Marty Medina, Vice Chair of the Board
SUBJECT: Approval of Appointments to the Executive Committee and the Audit and Finance Committee (Action)
Item No. 11
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Approve appointments to the Executive Committee and the Audit and Finance Committee.
DISCUSSION
Honorable Colleagues,
Peninsula Clean Energy Policy 16, “Selection of the Chair and Vice Chair and Appointment to the Executive Committee and other Standing Board Committees” provides guidance on the process to appointment members to the Executive Committee and Audit and Finance Committee as follows:
“The Board will be asked to cast a vote either for or against the entire slate at the March [April due to delay in Chair/Vice Chair appointments] Board meeting. In the event the Board does not approve the slate, any Board members may nominate individual members to the Executive Committee or the Board may direct the Chair to return at the April Board meeting with a new slate.”
Vice Chair Medina and I spoke with many Board members across our jurisdiction about their potential participation and we're thrilled to share that numerous highly qualified individuals have expressed their interest in serving, which is crucial for maintaining the Board's continuity and safeguarding institutional knowledge and develop future leadership talent. We extend our gratitude to everyone who has shown interest and participated in our discussions. We urge you all to keep exploring PCE's endeavors and mission. After these conversations, we are pleased to make the following appointments:
To the Executive Committee:
1. Dave Pine, San Mateo County
2. Ray Mueller, San Mateo County
3. Rick DeGolia, Atherton
97 4. Coleen Mackin, Brisbane
5. Donna Colson, Burlingame, Chair
6. Betsy Nash, Menlo Park
7. Anders Fung, Millbrae
8. Jeff Aalfs, Portola Valley
9. Marty Medina, San Bruno, Vice Chair
To the Audit and Finance Committee:
1. Tom McCune, Belmont
2. Donna Colson, Burlingame
3. Carlos Romero, East Palo Alto
4. Leslie Ragsdale, Hillsborough
5. Paul Llanez, Los Banos
Sincerely,
Donna Colson, Chair
Marty Medina, Vice Chair
98 DATE: April 19, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Shawn Marshall, Chief Executive Officer; Roy Xu, Director of Power Resources; Mehdi Shahriari, Manager of Planning and Analytics
SUBJECT: Approval of Updated Peninsula Clean Energy Strategic Plan Organizational Priority Number 1 to: Deliver 100% Renewable Energy on An Annual Basis by 2030 Through Strategic and Cost-Effective Procurement of Resources that Maximize Peninsula Clean Energy 24/7 Hourly Matching of Renewable Energy and Load (Action)
Item No. 12
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Approval of Updated Peninsula Clean Energy’s Strategic Plan Organizational Priority #1 to:
“Deliver 100% Renewable Energy on An Annual Basis by 2030 Through Strategic and Cost-Effective Procurement of Resources that Maximize Peninsula Clean Energy’s 24/7 Hourly Matching of Renewable Energy and Load.”
BACKGROUND
In 2017, Peninsula Clean Energy set an ambitious goal to deliver time-coincident [1] or 24/7 renewable energy to its customers by 2025. In November 2022, Peninsula Clean Energy clarified that the 24/7 renewable matching would occur for 99% of the hours (while maintaining 100% annual matching). In June 2023, the implementation date was extended to 2027 due to market challenges. In November 2023, Peninsula Clean Energy staff provided an overview of market conditions and the feasibility of implementing the 24/7 renewable goal by 2027, and the Board of Directors directed staff to evaluate adjustments to the 24/7 goal that would be more realistic and financially prudent based on the current market environment.
In March 2024, Peninsula Clean Energy updated its Strategic Plan Organizational Priority #1 to “Delivering 100% Renewable Energy Annually by 2030 Through Strategic Procurement of Resources to Maximize Peninsula Clean Energy’s 24/7 Hourly Renewable Matching Goal”.
This update pushed out the implementation date for the annual 100% renewable energy goal from 2025 to 2030, and was undertaken to help maintain lower rates for Peninsula Clean Energy’s customers while also continuing to pursue a 100% renewable portfolio well in advance of the State's RPS goal of 60% by 2030.
99 Since November 2023, staff has updated PCE's 24/7 renewable modeling with new pricing inputs and assumptions, explored methods to maintain 24/7 renewable energy over longer periods of time[2], and developed alternative structures to meet the goal while minimizing near and long-term cost and risk.
As discussed with the Board in June 2023, November 2023, and March 2024, market conditions have drastically changed in the past two years, inconsistent with the assumptions used in Peninsula Clean Energy’s original 24/7 analysis and published White Papers on the subject. This includes significant delays in development and commissioning of new renewable projects in general and lack of projects with desirable profiles for 24/7 time coincident matching, all of which are contributing to the need to adjust PCE's 24/7 renewable goal.
There are not many comparison points for PCE’s 24/7 renewable goal, but California's SB 100 is one benchmark. Under SB 100 (2017, De Léon), California retail sales are required to be 60% renewable by 2030 and 100% carbon-free by 2045. Although the statewide 2045 goal is not an hourly clean energy goal, it will effectively remove fossil fuel generation from the state resource mix and be similar to an hourly clean energy goal. Under the Joint Agency Report released in 2021, it is estimated that meeting the SB 100 goal for 2045 will require California to build almost 50 GW of new resources by 2030 and 170 GW by 2045. PCE’s approximate share of that new capacity is 700 MW by 2030 and 3,500 MW by 2045. With PCE’s currently executed contracts, it has met its share of the SB 100 goal by 2030 several years ahead of schedule. In 2027, PCE is projected to achieve 86% annual renewable content and 77% hourly matching with its existing resource portfolio.
[1] Peninsula Clean Energy uses the term "24/7", "hourly", or "time-coincident" to mean delivering renewable energy that matches customer demands each and every hour of the day.
Staff uses these terms interchangeably throughout this memo. [2] Previous 24/7 analyses have been limited to a single year and have not explored the long-term costs and risks of maintaining the 24/7 renewable goal over many years.
DISCUSSION
In the latest 24/7 modeling, staff shifted the main analysis year from 2027 to 2030 due to the afore-mentioned resource availability challenges in the near term. In addition, staff analyzed several important variables in the updated analysis of the 24/7 renewable goal:
1. Resource Availability: In the current market, there is limited availability of key resources to make progress towards the 24/7 renewable goal. More resources may become available by the turn of the decade, as illustrated in Figure 1. Staff considered two resource availability scenarios in our analysis, “Realistic” and “Optimistic”. The "Realistic" scenario assumes fewer resource types are available, and no "best-fit" resources. The "Optimistic" scenario, which staff deemed to be less likely to manifest, assumes that more resources are available, including adequate amount of wind and geothermal resources, which are a better fit for PCE's portfolio. 100
Figure 1: Current Resource Availability
2. Market Price Scenarios: Staff considered two market price scenarios: the “High Market” scenario where market prices remain elevated in the medium term, and the “Low Market” scenario, where market prices decline over the medium term. These scenarios don’t represent the most extreme possibilities that the market may experience, but instead represent reasonable ranges for what may happen. The market price scenarios explore uncertainties around prices and PCE’s ability to resell excess products. The Low Market presents more challenges for PCE, because of the difficulties with reselling any excess procurement, which leads to significantly higher cost and risk for PCE.
3. Resale scenarios: Staff analyzed several resale structures for excess procurement.
There are fundamental tradeoffs between cost and risk in structuring resale products.
Bundled products (selling energy, capacity, and environmental attributes together) provide a lower resale value to PCE, but could reduce uncertainties. Unbundled products (selling energy, capacity, and environmental attributes separately) provide higher resale value to PCE, but creates more uncertainties. Staff uses the "Medium" resale scenario as a default assumption, and considered the changes in cost and risk if PCE were to pursue the Aggressive or Conservative resale approaches.
Table 1: Resale Scenarios
Resale Scenarios Bundled Sale Unbundled Sale
Conservative 100% 0%
Aggressive 0% 100%
Medium 60% 40%
Using these assumptions, staff performed an analysis of additional capacity needed in order to achieve a range of 24/7 renewable targets under different scenarios (Figure 2). Under the Realistic resource availability assumptions, PCE will need to procure a significant amount of capacity from new resources to achieve higher 24/7 renewable targets. The large capacity from new resources will lead to higher over-procurement, thus resulting in higher risk.
However, under the Optimistic resource availability assumptions, PCE would procure resources that provide better fit in our portfolio, thus reducing over-procurement, which in turn lowers cost and risk. Delivering 100% renewable energy on an annual basis by 2030, through strategic procurement of new resources, could by default result in 24/7 renewable matching of 101
80% to 85%.
Figure 2: Additional Capacity Needed by 2030
Staff also analyzed the portfolio needs to maintain a 24/7 renewable goal over several years (Figure 3). Staff found that due to expiration of existing contracts and forecasted load growth, PCE will need to continue to add new resources to its portfolio to maintain a high time-coincident target. Uncertainties around market conditions and resource availability will continue to impact PCE's procurement decisions beyond the initial target year. 102
Figure 3: Maintaining the 24/7 Goal Over Time (Example for the Hourly 90% Scenario) Furthermore, staff analyzed the magnitude of over-procurement under a variety of scenarios and found that over-procurement increases as the hourly matching target increases. Over-procurement leads to risk in PCE's portfolio, because it exposes PCE to market volatility. In addition, over-procurement risk could stack with PCIA (i.e. exit fee) risk, leaving PCE significantly exposed to low market prices. As shown in Figure 4, over-procurement is substantially higher if the Realistic resource availability assumption manifests. In comparison, over-procurement could be much reduced if resources available under the Optimistic case do become available. Notably, the annual 100% renewable scenario would result in no over-procurement measured against annual load volume, while achieving between 80% to 85% hourly renewable matching.
103
Figure 4: Over-Procurement Under Different Scenarios
Staff further analyzed the portfolio cost of energy for a variety of 24/7 renewable targets under the Realistic and Optimistic resource availability cases, as well as under the High and Low Market price scenarios. Resale scenarios were also evaluated and are shown in Tables 2 and 3 as an uncertainty in cost in parentheses. In general, higher time-coincident scenarios create higher cost and risk to PCE, especially under the Realistic resource availability case. By comparison, under the Optimistic resource availability case where desirable resources are available to contract, cost and risk would be manageable to reach a higher time-coincident target.
Table 2: Realistic Case in 2030 - Increase in Cost of Energy Relative to the Lowest Cost Scenario (i.e. the Annual 100% in High Market); the value in parenthesis represents potential additional cost due to uncertainties in resale value of excess products. For example, the Hourly 90% scenario in a High Market price environment could increase annual cost of energy by $14 million relative to the Annual 100% High Market case, and the increase could be as high as $25 million (i.e. $14M + $11M) with unfavorable resale outcome.
Scenario High Market Low Market
Annual 100% 0 (3) 15 (0)
Hourly 90% 14 (11) 45 (3)
Hourly 95% 50 (33) 114 (10)
104
Table 3: Optimistic Case in 2030 - Increase in Cost of Energy Relative to the Lowest Cost Scenario (i.e. the Annual 100% in Low Market); the value in parenthesis represents potential additional cost due to uncertainties in resale value of excess products. For example, the Hourly 90% scenario in a High Market price environment could increase annual cost of energy by $4 million relative to the Annual 100% Low Market case, and the increase could be as high as $7 million (i.e. $4M + $3M) with unfavorable resale outcome.
Scenario High Market Low Market
Annual 100% 3 (2) 0 (0)
Hourly 90% 4 (3) 2 (0)
Hourly 95% 15 (11) 25(2)
In conclusion, with PCE’s current executed contracts, PCE could achieve approximately 77% time-coincident renewable energy by 2027. However, meeting any higher time-coincident targets in 2027 through 2029 would be infeasible due to current market conditions, project delays, and lack of desirable resources. PCE could achieve 80% to 85% time-coincident renewable energy (24/7 matching) by 2030 through meeting the annual 100% renewable energy goal. However, meeting any higher time-coincident targets by 2030 would add cost and risk to PCE’s portfolio. Differences in emissions and grid impacts between PCE’s 85% and 95% time-coincident renewable portfolios are estimated to be small given PCE’s load share of the grid, but such increase in time-coincident percentage could lead to significantly higher costs to PCE’s customers. If and when better-fit resources such as wind and geothermal become available in the market, it would be more cost-effective to achieve 24/7 renewable matching at or above 90%.
In consideration of these conclusions, Staff has prepared three options for the Board’s consideration for how to implement the 24/7 renewable energy goal.
1. Adjust the 24/7 renewable energy target to 2030
Adjust the target by lowering the time-coincident percentage and shifting to a later target year to achieve a sweet-spot between high renewable hourly matching and keeping cost of energy reasonable.
This option could demonstrate a relatively high hourly matching goal consistent with previous messaging, but would be more expensive and risky, and could necessitate future revisions to the goal if market conditions prove this target to be infeasible. There will also be challenges to maintaining the goal in the long term.
2. Use an average 24/7 renewable energy target over 5 years, starting in 2030 Set a time-coincident target averaged over a 5-year period beginning in 2030. This would mean PCE's 24/7 renewable matching percentage could fluctuate within the measurement period, but the average percentage would meet an approved target set by the Board.
This option would allow more flexibility to address contract expiration and load growth, as well as discretion if there are no best-fit resources available to contract.
However, maintaining an average goal of (for example) 90% time-coincident renewable matching could still increase cost and risk to our customers, especially under the Realistic resource availability scenario. The averaging concept could also be difficult to communicate.
3. Maintain the 100% annual renewable energy goal with a flexible hourly target 105
Maintain the 100% annual renewable energy goal every year starting in 2030 through strategic procurement of resources to maximize hourly matching.
This option would be the most affordable, potentially offering the lowest rates to customers. It would provide the most flexibility to build an optimal portfolio by not imposing additional constraints. It would maximize flexibility to address contract expiration and load growth while minimizing over-procurement cost and risk.
However, this option may result in a perception of PCE moving away from our aggressive 24/7 renewable goal.
Upon collecting inputs from the Procurement Subcommittee on April 9, 2024, staff recommends Option 3 as the best way forward to make meaningful progress towards the 24/7 renewable goal, and at the same time supporting PCE customers in electrification efforts by keeping cost of energy affordable.
In a market where renewable supplies are limited and delayed by multiple external factors, PCE is facing challenges on its journey to serve its customers with renewable energy every hour of the day. Achieving 99% time-coincident renewable power by 2027 is no longer feasible, but PCE will still be able to achieve close to 80% hourly renewable matching by 2027 with its current portfolio of resources, which is an industry-leading accomplishment worth noting. Both the PCE Board and staff are clear that 24/7 renewable matching remains a key priority for the agency, and are committed to reaching this goal as soon as market conditions improve and a more diverse set of resources become commercially available. PCE’s procurement decisions going forward will be strategically focused on maximizing hourly renewable matching while minimizing additional costs for its customers.
An important component to continued pursuit of this goal is the critical learning and thought leadership that results in the planning, modeling and incremental operationalization of hourly renewable matching. PCE is proud of the innovative work by its staff in these areas, including the development of the open-source MATCH model, the release of two analytical White Papers, and the ongoing refinement to the modeling assumptions, reflecting updated cost and risk impacts of pursuing this goal in today’s market environment. PCE intends to remain at the forefront of the industry’s evolution towards 100% hourly renewable and will continue to share recommendations and lessons-learned along the way.
FISCAL IMPACT
Adopting staff’s recommendation would not affect FY 23-24 costs. The recommended flexible approach to the hourly matching goal will reduce future procurement costs and be reflected in future year budgets.
STRATEGIC PLAN
Staff's recommendation would modify the portion of Organizational Priority Number 1 in Peninsula Clean Energy's Strategic Plan with respect to the 24/7 renewable matching target.
Approval of this Recommendation will revise the priority statement from "Delivering 100% Renewable Energy Annually by 2030 Through Strategic Procurement of Resources to Maximize Peninsula Clean Energy’s 24/7 Hourly Renewable Matching Goal" to "Deliver 100% renewable energy on an annual basis by 2030 through strategic and cost-effective procurement of resources that maximize Peninsula Clean Energy’s 24/7 hourly matching of 106
renewable energy and load.”
Staff anticipates incorporating changes to the priority statement as part of the mid-year review of the Strategic Plan to be presented to the Executive Committee on May 13, 2024. 107
RESOLUTION NO. _____________
PENINSULA CLEAN ENERGY AUTHORITY, COUNTY OF SAN MATEO, STATE OF
CALIFORNIA
APPROVAL OF UPDATED PENINSULA CLEAN ENERGY STRATEGIC PLAN ORGANIZATIONAL PRIORITY NUMBER 1 TO: DELIVER 100% RENEWABLE ENERGY ON AN ANNUAL BASIS BY 2030 THROUGH STRATEGIC AND COST-EFFECTIVE PROCUREMENT OF RESOURCES THAT MAXIMIZE PENINSULA CLEAN ENERGY 24/7
HOURLY MATCHING OF RENEWABLE ENERGY AND LOAD (ACTION)
WHEREAS, the Peninsula Clean Energy Authority (“Peninsula Clean Energy”) was formed on February 29, 2016; and
WHEREAS, in 2017, Peninsula Clean Energy set an ambitious goal to deliver 24/7 renewable energy that matches customer demand each and every hour of the day by 2025; and WHEREAS, in November 2022, Peninsula Clean Energy specified that 24/7 renewable energy would be delivered to match 99% of hourly load, and at least 100% of annual load; and WHEREAS, in June 2023, Peninsula Clean Energy updated the target date to implement 24/7 renewable energy to 2027, in light of cost and resource availability; and WHEREAS, staff modeling and analysis of current available resources and current market conditions indicate that meeting a 99% hourly renewable target in 2027 would be infeasible; and
WHEREAS, staff modeling and analysis indicate that driving to 100% renewable energy on an annual basis by 2030 by procuring resources to maximize hourly matching will reduce cost and optimize portfolio structure.
NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board adopts the staff’s recommendation to revise Peninsula Clean Energy's Organizational Priority Number 1 of the Strategic Plan to: Deliver 100% renewable energy on an annual basis by 2030 through strategic and cost-effective procurement of resources that maximize Peninsula Clean Energy’s 24/7 hourly matching of renewable energy and load. 108
DATE: April 18, 2024
MEETING DATE: April 25, 2024
VOTE REQUIRED: Majority Vote
TO: Honorable Peninsula Clean Energy Authority Board of Directors FROM: Nicholas Bijur, Chief Financial Officer
SUBJECT: Approval of Continued Evaluation and Preparation for a Possible Prepay Bond Transaction, Including Approval to Join the California Community Choice Finance Authority and the Engagement of a Financial Advisor and Prepay Counsel (Action)
Item No. 13
PENINSULA CLEAN ENERGY AUTHORITY
JPA Board Correspondence
RECOMMENDATION
Approve continued evaluation and preparation for a possible Prepay bond transaction potentially in late 2024, including approval to join the California Community Choice Finance Authority (CCCFA) as an associate member at the appropriate time as conduit for the bond issuance, and the nearer term engagement of PFM Financial Advisors (PFM) as Municipal Financial Advisor and Chapman and Cutler as Prepay Counsel.
BACKGROUND
An energy prepayment – or ‘Prepay’ – is a long-term financial transaction available to municipal utilities and tax-exempt entities such as CCAs that enables a meaningful power procurement cost savings opportunity. The Prepay structure has historically been utilized for natural gas procurement and is now being applied in the renewable energy sector. Over the past 2½ years there have been 11 Prepay transactions involving six different California CCAs, raising $10 billion in bond proceeds and generating approximately $60 million in annual energy procurement cost savings.
Staff have been evaluating Prepays for almost a year to familiarize themselves with the structure, process, benefits, and risks. Garth Salisbury, Chief Financial Officer at MCE Clean Energy (MCE) and Board Member/Treasurer of CCCFA, presented to Peninsula Clean Energy’s (PCE) Audit & Finance Committee in June 2023. MCE has executed two Prepay transactions and CCCFA has been the conduit issuer for those two and the additional nine CCA Prepay transactions completed by Ava Community Energy, Silicon Valley Clean Energy, Pioneer Community Energy, Clean Power Alliance, and Central Coast Community Energy.
After extensive further research, staff provided an updated Prepay presentation to the Audit & Finance Committee in February 2024, and Rick Degolia, Donna Colson and Carlos Romero met with Garth Salisbury and Doug Bird from Chapman and Cutler in March 2024 to better 109
understand the Prepay structure, its benefits, and possible risks. Staff also presented to the Executive Committee in early April, which unanimously approved the recommendation being presented herein to the Board of Directors.
Prepay Process
Utilizing the municipal bond market, a tax-exempt Load Serving Entity such as Peninsula Clean Energy (LSE, also called “Prepay Buyer”) and a taxable financial counterparty (bank, called “Prepay Supplier") enter into a 30-year agreement through which the LSE assigns existing power supply contracts (or power purchase agreements, “PPAs”) to the Prepay Supplier. The Prepay Supplier pays the contract price to the PPA provider, while the LSE pays the Prepay Supplier at a discounted rate. The discounted rate is agreed upon in the Prepay documents and is based in large part on the spread between the taxable and tax-exempt bond interest rates. The market availability of this interest rate spread is critical to the savings opportunity available to the LSE.
Tax-exempt bonds are issued by a third-party conduit such as CCCFA to raise funds for the Prepay transaction. The funds flow from the conduit issuer (CCCFA) to the Prepay Supplier.
The LSE does a limited assignment of one or more of their long-term PPAs to the Prepay Supplier. The LSE is required to continue to perform under the contract, while maintaining rights to the electricity and attributes under the PPA. The Prepay Supplier utilizes the bond funds and provides a discount on the PPA to the LSE based on the spread between the taxable and tax-exempt interest rates. The discount over the past 2½ years has ranged from 8-12% but is subject to change based on market conditions.
The tax-exempt bonds are issued with an initial maturity of 6-8 years (exact maturity depends on market conditions at the time of issuance). The interest rate at this point on the yield curve provides optimal savings due to dynamics in the tax-exempt bond market. After 6-8 years the bonds are “remarketed” to investors and the savings over the subsequent 6-8 years will depend on the market conditions at the time of the remarketing. If the savings at the time of the remarketing are deemed insufficient (typically less than 5%), PCE can terminate the transaction with no penalty.
While the contracts are assigned to the Prepay Supplier, the LSE continues to ultimately take and pay for all the energy and attributes delivered through the contract; all other terms of the PPA remain unchanged. If the Prepay terminates early for any reason – either the Prepay Supplier fails to perform or the savings after the remarketing are not sufficient – the LSE forgoes future savings and the assigned PPA is returned completely to the LSE.
DISCUSSION
Based on current market conditions, a preliminary evaluation of PCE’s current PPAs, and exploratory conversations with various Prepay advisors, it is estimated that an initial Prepay transaction will generate approximately $3.5 million in annual energy cost savings which could be used to lower customer rates. The indicative size of the Prepay transaction and associated savings assume the inclusion of three of PCE’s existing PPAs; the final number of PPAs and which ones are included in the transaction will be refined over the next 3-6 months. The savings are based largely on the spread between taxable and tax-exempt interest rates, which is currently relatively wide thus creating a favorable market environment for Prepay transactions. PCE may be able to increase the size of the initial transaction and/or execute subsequent transactions with additional or future PPAs, thereby increasing the amount of 110
annual savings. Limitations on sizing are based on investor demand, market conditions with meaningful taxable/tax-exempt spreads, and the available headroom to ensure PCE will have procurement-related costs to assign in a 30-year transaction.
The primary risk is if the Prepay program terminates early for any reason, in which case PCE forgoes future savings but is no worse off than had it not executed the transaction at all. The fees paid to the various service providers are contingent on executing a transaction and are paid from the bond proceeds. If the transaction does not move forward or never occurs for whatever reason, the advisors are not paid. The above-mentioned estimated savings are after paying all transaction costs.
It is estimated to take approximately 6-9 months to execute a Prepay transaction and will require significant staff time. PCE is required to hire a Municipal Financial Advisor who will assist in the process. Staff recently completed an RFP process and recommend hiring PFM as its Prepay Financial Advisor. PFM has worked on seven of the 11 CCA Prepays and is very knowledgeable about Prepay bond finance and the CCA industry. PCE also has a prior working relationship with PFM and is comfortable with their team. The estimated fee to PFM is $350,000, which consists of $300,000 for financial advisory and up to $50,000 for swap advisory, both of which are paid out of bond proceeds and only if the transaction closes.
Staff also recommend engaging Chapman and Cutler as Prepay Counsel, and CCCFA will engage Orrick Herrington & Sutcliffe (Orrick) as Tax and Bond Counsel on PCE’s behalf.
Chapman and Cutler and Orrick have worked in partnership on almost all the CCA Prepay transactions and have significant subject matter expertise; estimated fees are $225,000 and $350,000, respectively, under the same terms as PFM. Note that the terms and conditions for all three vendors are substantially similar to prior CCA Prepay transactions.
Finally, staff recommend joining CCCFA as an associate member at the appropriate time and only if PCE moves forward with a Prepay transaction. CCCFA has been the conduit issuer for all CCA Prepay transactions and membership is required to execute a transaction. The membership fee is $50,000. Because the membership fee is not contingent on a successful transaction and would be a “sunk cost” if we do not proceed, staff will wait as long as possible before joining CCCFA, likely sometime over the summer or early fall. In addition, each member of CCCFA is responsible for paying an equal portion of CCCFA’s general and administrative operating costs as determined by its board, which is estimated to be approximately $20,000 per year.
Staff will provide periodic updates to the Executive Committee and Audit & Finance Committee and plans to seek transaction approval from the Board of Directors a few months prior to execution. This will include a resolution authorizing the execution of a power supply contract with CCCFA, parameters of a transaction, and approval to enter into certain other documents to enable PCE to complete a Prepay transaction.
FISCAL IMPACT
The purpose of pursuing a Prepay transaction is to achieve meaningful energy procurement cost savings. Based on preliminary analysis and conversations with advisors, an initial transaction will result in approximately $3.5 million in annual procurement cost savings. The amount of savings is dependent on which PPAs are included in the transaction and market 111
conditions and will be refined over the next six months.
The fees paid to the various parties involved in the Prepay are contingent on a successful transaction and payable from the proceeds of the bonds. As a result, there is no out-of-pocket cost to PCE; the cost will be paid out of the savings realized from the Prepay transaction. If a transaction does not occur, the only costs to PCE would be the membership fee to join CCCFA ($50,000) and the fees owed to the rating agency (approximately $200,000); both costs will be incurred late in the process.
Additionally, it is important to note that the Prepay is non-recourse to PCE. The ultimate counterparty with the Prepay Supplier is CCCFA, so CCCFA is therefore the counterparty to all the underlying agreements. CCCFA is a separate public entity and the debts, liabilities and obligations of CCCFA will not constitute debts, liabilities or obligations of PCE.
ATTACHMENTS:
04-25-2024 Board Presentation.pdf
PCE - PFM Swaps Contract 2024.docx
2024 PCE PFM FA Contract.docx
PCE Chapman Cutler Engagement Agreement.docx
112
RESOLUTION NO. _____________
PENINSULA CLEAN ENERGY AUTHORITY, COUNTY OF SAN MATEO, STATE OF
CALIFORNIA
APPROVAL OF CONTINUED EVALUATION AND PREPARATION FOR A POSSIBLE
PREPAY BOND TRANSACTION, INCLUDING APPROVAL TO JOIN THE CALIFORNIA
COMMUNITY CHOICE FINANCE AUTHORITY AND THE ENGAGEMENT OF A FINANCIAL
ADVISOR AND PREPAY COUNSEL (ACTION)
RESOLVED, by the Peninsula Clean Energy Authority of the County of San Mateo, State of California (“Peninsula Clean Energy” or “PCE”), that
WHEREAS, the Peninsula Clean Energy Authority (“PCEA”) was formed on February 29, 2016, as a Community Choice Aggregation program (“CCA”); and WHEREAS, the use of energy prepayment on a tax advantaged basis enables a meaningful power procurement cost savings opportunity in which PCE can utilize its tax-exempt status to access the municipal bond market to prepay energy supply contracts at a discount rate; and WHEREAS, long-term power prepay transactions utilize the municipal bond market and as such, require that PCE become a member of a bond issuing entity in order to participate; and WHEREAS, the California Community Choice Financing Authority (“CCCFA”) is a joint exercise of powers agency established under California Government Code section 6500 et seq. (the “JPA Law”) and a Joint Powers Agreement (the “CCCFA Joint Powers Agreement”) among various CCAs for the purpose of undertaking the financing and refinancing of energy prepayments that can be financed with tax advantaged bonds on behalf of one or more of its members by, among other things, issuing or incurring bonds and entering into related contracts; and
WHEREAS, PCE is a community choice aggregator, as such term is defined in Section 331.1 of the Public Utilities Code of the State of California (the “Public Utilities Code”), that is also a public agency, as such term is defined in the JPA Law, which has implemented a CCA program pursuant to Section 366.2 of the Public Utilities Code, and possesses the power to purchase and sell electric energy and enter into related contracts for such purposes and, therefore, PCE is eligible to become a member of CCCFA pursuant to the terms of the CCCFA Joint Powers Agreement; and
WHEREAS, for CCCFA to finance or refinance energy prepayments and issue bonds on behalf of PCE, PCE must become a member of CCCFA; and
WHEREAS, PCE has determined that CCCFA is the best-fit least-cost option to serve as a bond issuing entity to enable PCE to participate in one or more energy prepayment 113
transactions and therefore PCE desires to become an associate member of CCCFA; and WHEREAS, to become an associate member of CCCFA, this Board must file an executed counterpart of the CCCFA Joint Powers Agreement with CCCFA, together with a copy of the resolution of the Board of Directors of PCE approving the CCCFA Joint Powers Agreement and the execution and delivery hereof, and requesting to be added as an associate member of CCCFA and PCE must further agree in writing to pay CCCFA a share of organization, planning and other costs and charges as determined by the Board of CCCFA to be appropriate, if any; and
WHEREAS, on March 11, 2022, the CCCFA Board established a membership entry fee of $50,000 for a new associate member’s portion of organization, planning, and other costs, in addition to each member’s equal share of general and administrative costs as determined by the CCCFA Board; and
WHEREAS, on December 16, 2022, the CCCFA Board established a transaction fee of $20,000 to cover the “Prepayment Project” costs as defined in Section 1.11 of the CCCFA Joint Powers Agreement; and
WHEREAS, under the JPA Law and the CCCFA Joint Powers Agreement, CCCFA is a public entity separate and apart from the parties to the CCCFA Joint Powers Agreement, and the debts, liabilities, and obligations of the CCCFA will not constitute debts, liabilities, or obligations of the PCE; and
WHEREAS, in addition to membership in CCCFA, PCE must engage a Municipal Financial Advisor and engage specialized prepayment legal counsel to advise on and help prepare for an energy prepay transaction; and
WHEREAS, after research and conducting an interview process, PCE has selected PFM Financial Advisors LLP as Financial Advisor and Chapman and Cutler LLP as Prepay Counsel; and
WHEREAS, PCE seeks the Board’s approval of agreements with PFM Financial Advisors LLP for financial advice services associated with a possible prepay transaction in an amount not to exceed $350,000; and
WHEREAS, PCE also seeks the Board’s approval for an agreement with Chapman and Cutler LLP for legal services associated with a possible prepay transaction in an amount not to exceed $250,000;
NOW, THEREFORE, IT IS HEREBY DETERMINED AND ORDERED that the Board of Directors hereby authorizes Peninsula Clean Energy’s continued evaluation and preparation for a possible prepay transaction and in aid of such delegates authority to the Chief Executive Officer, in consultation with PCE’s General Counsel, to finalize and execute agreements establishing PCE as a member of the CCCFA, with PFM Financial Advisors LLP in an amount not to exceed $350,000, and with Chapman and Cutler LLP in an amount not to exceed $250,000.
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Prepay Transaction
Board of Directors Meeting
April 25, 2024
115
Peninsula Clean Energy
Background
• Prepay is a long-term financial transaction available to tax-exempt entities, such as CCAs, that enable meaningful power procurement cost savings
o Savings based on spread between taxable and tax-exempt interest rates o Codified in US tax law
• Historically utilized for natural gas procurement, now being applied in renewable energy sector • To date, 11 CCA Prepay transactions generating ~$60 million annual savings (see next page) • Savings of 8-12% based on current market conditions
• Initial PCE transaction could generate $3.5 million of annual savings (assumes 3 existing PPAs; amount to be refined)
• Process will take 6-9 months and requires engagement of multiple advisors and membership in California Community Choice Finance Authority (CCCFA)
• Audit & Finance Committee has been briefed on the topic twice (June 2023 and February 2024), and Executive Committee recently unanimously approved pursuing a possible transaction 2116
Peninsula Clean Energy
CCCFA Pre-Pay Transactions
3 Date Project Participant(s) Par ($M)
Prepaid
Supplier
Annual
Savings ($M) Discount(1)
September 2021 East Bay Clean Energy/Silicon Valley Clean Energy $1,235 Morgan Stanley 4.1 7.3% November 2021 Marin Clean Energy 603 Goldman Sachs 4.2 10.0% July 2022 East Bay Clean Energy 931 Morgan Stanley 2.9 9.0% January 2023 Pioneer Community Energy 460 Goldman Sachs 2.4 n/a January 2023 Silicon Valley Clean Energy Authority 842 Morgan Stanley 4.5 9.5% February 2023 Clean Power Alliance 999 Goldman Sachs 8.3 13.6% June 2023 Clean Power Alliance 958 Goldman Sachs 6.4 12.0% August 2023 East Bay Community Energy Authority 998 Goldman Sachs 6.9 12.2% October 2023 Central Coast Community Energy 648 Morgan Stanley 5.0 12.2% December 2023 Marin Clean Energy 1,038 Goldman Sachs 6.8 12.0% January 2024 Silicon Valley Clean Energy 1,102 Morgan Stanley 7.7 13.1% $ 9,813
1. Goldman and Morgan Stanley calculate discount differently, so hard to compare apples-to-apples Clean Power Alliance, San Jose Clean Energy, and San Diego Community Power are rumored to be proceeding with transactions
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Peninsula Clean Energy
Benefits and Rationale
1. Source of cost savings that can lower customer rates o 8-12% on power quantities delivered, or ~$3.5 million per year based on indicative terms on an initial transaction
o Savings fluctuate depending on market conditions and size of transaction o Can execute additional transactions over time to increase amount of savings (limitation based on investor demand, market conditions, and PCE forecasted load)
2. Service provider fees paid from bond proceeds on a contingency basis o If bonds are not issued, service providers are not paid o Only “sunk” costs are staff time, CCCFA membership ($50k), and rating agency (~$200k)
3. PCE not responsible for bond repayment / debt non-recourse to PCE 4118
Peninsula Clean Energy
Risk/Considerations and Mitigations
5 Savings realized through termination
date and PCE no worse off Prepay terminates earlier than expected Possibility of multiple Prepays hedges
timing risk Market timing
Leverage prior CCCFA transactions
and support from Financial Advisor Staff time
Potentially hire additional back-office
staff Increased settlement complexity
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Peninsula Clean Energy
Assembling the Pre-Pay Deal Team
Municipal Advisor Prepay Counsel Conduit Issuer Prepaid Supplier Custodian / Trustee Rating Agency Bond / Tax Counsel
Peninsula Clean Energy
Entities selected
by PCE
Other Entities
in Prepay
Deal • Financial advisory
• Advice on structure,
timing and terms
• Fiduciary responsibility to
CCA
• PFM(1)
• Legal advisory
• Represents CCA’s
interests
• Chapman and Cutler (1)
• Issuer of tax-exempt
bonds
• CCCFA
• Structures transaction
• Markets and underwrites
bonds
• Morgan Stanley,
Goldman, RBC (1)
• Legal services
• Affirms tax-exempt bond
status and validity of
bond offering
• Orrick(1)
• Rates bonds
• Moody’s
• Manges prepay estate
• Bond interest payments
• US Bank, Wells Fargo (1)
6 Green Font = potential service providers
(1) Fees paid on contingency from Bond proceeds
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Peninsula Clean Energy
Preliminary Timeline
Contract with
Service
Providers
Structure
Prepay Deal
Prepare for
Transaction
Launch
Mar Apr May Jun Jul Aug Sep Oct Nov………
RFP for Financial Advisor
and Engage Counsel
RFP for Investment
Bank
Join CCCFA
Structure prepay transaction
Engage ratings
agency
Confirm PPA
assignments
Finalize deal
documents
Prepare “form of” deal
documents
Feb
Board approval of transaction 7121
Peninsula Clean Energy
Recommendations and Next Steps
• Approval to continue evaluation and pursuit of a possible Prepay transaction o Savings are material, risks are negligible, and upfront costs are minimal o Can pause process at any time
• Approval to engage selected advisors (paid on contingency) o PFM Financial Advisors as Financial Advisor
o Chapman and Cutler as Prepay Counsel
o Orrick, Herrington & Sutcliffe as Bond and Tax Counsel (engaged by CCCFA) • Approval to join CCCFA as an affiliate member at the appropriate time (late summer or early Fall) • Staff will return to the Audit & Finance Committee and Executive Committee with periodic updates and will seek Board approval of a transaction prior to launch 8122
Appendix
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Peninsula Clean Energy
Why Now?
10 Elevated Interest Rate Environment:
Tax-exempt bonds’ yield advantage versus
corporate rates is the greatest in over a
decade
Procurement of Renewables with PPAs is
Commonplace: PCE has a portfolio of
PPAs suitable for one or more prepay
transaction
Prepay Documentation is Tried and True:
Structure has evolved over the years so that
current documents optimize savings,
minimize participant risks and provide for
seamless monthly settlements
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Peninsula Clean Energy
Indicative PCE Prepay Transaction Terms
• Initial bond offering (pre-payment amount) of $550 million o Assumes assignment of three operating PPAs, representing 1 million MWh annually o Notional value of assigned contracts over 30-years ~$1 billion o PCE can assign additional PPAs to increase size of transaction or execute subsequent transactions
• Initial savings of ~$3.5 million per year, or 10% of contracted PPA payments • Savings locked-in for seven years, after which bonds re-issued with a minimum discount of 5% (to be negotiated)
o If minimum savings not met at reissuance date, PCE can walk away from transaction and assigned PPAs are put back to PCE; PCE forgoes future savings • Transaction fees, including advisors, payable from proceeds of the bond offering and included in savings analysis
11125
Peninsula Clean Energy
Maximizing Savings
12 • Savings driven by the “spread” between tax-exempt and taxable interest rates • Recent transactions, on average, have priced with 6-8 year initial periods to strike balance between savings and length of initial term
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Peninsula Clean Energy
Transaction Diagram
Initial Issuance and Cash Flows
1. Debt Issuance – CCCFA issues tax-exempt bonds
2. Prepayment – CCCFA remits bond proceeds to Prepay
LLC in return for 30 years of assigned electricity deliveries
3. Unsecured Loan – Prepay LLC loans bond proceeds to
Intermediary Bank. Bank makes fixed monthly payments
to Prepay LLC equal to assigned electricity multiplied by PPA price
Monthly Cash / Energy Flows
4. Assigned PPAs – PCE assigns to Prepaid Supplier certain rights and obligations as Buyer; Prepaid Supplier makes monthly payments to PPA counterparties for assigned
delivered energy
5. Electricity Supply – Prepay LLC enters into long-term agreement to purchase electricity from Prepaid Supplier to match assigned electricity quantities/terms
6. Project Participant – CCCFA sells PCE all assigned
electricity delivered by Prepay LLC at the discounted
prepay price
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Peninsula Clean Energy
PPA Assignment Concept
14 PPA Seller Prepaid Supplier
(GS, MS or RBC)
Status Quo
PPA Seller
PCE enters into PPA with
PPA Seller
PPA Seller delivers as generated
power/attributes
PCE pays monthly for as-generated (or fixed
volume) power and attributes
Power +
Attributes
Contract Price
Proposal
Power +
Attributes
Structures remains the same, but instead
of facing PCE, the PPA Seller faces
Goldman Sachs, Morgan Stanley or RBC
If the Prepaid Supplier fails to pay, PCE
guarantees payments (which it is able to
recoup from the Prepay Trust Estate)
Under certain scenarios, assignment
can be terminated, and PPA Seller
goes back to facing PCE
The existing Scheduling Coordinator
will remain the Scheduling
Coordinator; only change is that the
Prepaid Supplier is copied on bills
Contract Price Contract Price
In event the Prepaid Supplier fails to
perform, PCE guarantees payment
Power +
Attributes
128
Rev. 07.31.2023
PFM SWAP ADVISORS LLC
AGREEMENT FOR SWAP ADVISORY SERVICES
This agreement (“Agreement”), made and entered into this 29th day of April, 2024 by and between Peninsula Clean Energy (“PCE”) and PFM Swap Advisors LLC (hereinafter called (“PFMSA”), sets forth the terms and conditions under which PFMSA shall provide services.
WHEREAS, PCE desires to obtain the services of a swap advisor to assist PCE with an energy prepayment transaction expected to be issued by the California Community Choice Financing Authority; and
WHEREAS, PFMSA is capable of providing the necessary swap advisory services.
NOW, THEREFORE, in consideration of the above-mentioned premises and intending to be legally bound hereby, PCE and PFMSA agree as follows:
I. SCOPE OF SERVICES
PFMSA shall provide, upon request of PCE, services related to swap advisory, as applicable and set forth in Exhibit A to this Agreement. PCE acknowledges and agrees that most tasks requested by PCE will not require all services provided for in Exhibit A and as such the specific scope of services for such task shall be limited to just those services required to complete the task. Any material changes in or additions to the scope of services described in Exhibit A shall be promptly reflected in a written supplement or amendment to this Agreement. Services provided by PFMSA which are not specifically referenced in the scope of services set forth in Exhibit A of this Agreement shall be completed as agreed in writing in advance between PCE and PFMSA. Upon the request of PCE, an affiliate of PFMSA or a third party referred or otherwise introduced by PFMSA and/or designated by PCE may agree to additional services to be provided under a separate writing, including separate scope and compensation, between PCE and such affiliate or third party.
II. WORK SCHEDULE
The services of PFMSA are to commence as soon as practicable after the execution of this Agreement and a request by PCE for such service.
III. REGISTERED MUNICIPAL ADVISOR; REQUIRED DISCLOSURES
1. PFMSA is a registered municipal advisor with the Securities and Exchange Commission (the “SEC”) and the Municipal Securities Rulemaking Board (the “MSRB”), pursuant to the Securities Exchange Act of 1934 Rule 15Ba1-2. As of the date of this Agreement, PCE has not designated PFMSA as its independent registered municipal advisor (“IRMA”) for purposes of SEC Rule 15Ba1-1(d)(3)(vi) (the “IRMA exemption”). PCE agrees not to represent that PFMSA is PCE’s IRMA with respect to any aspect of a municipal securities issuance or municipal financial product, without PFMSA’s prior written approval. 129
Rev. 07.31. 2023 - 2 -
2. MSRB Rules require that municipal advisors make written disclosures to their clients of all material conflicts of interest, certain legal or disciplinary events and certain regulatory requirements. Such disclosures are provided in PFMSA’s Disclosure Statement delivered to PCE prior to or together with this Agreement. Refer to Exhibit D.
3. PFMSA agrees that it will not deal with itself or with any other affiliated company or individual in making purchases or sales of the swap(s) or any securities pursuant to this engagement, nor will we take a long or short position in securities subject to purchase or sale in connection with the swap(s). PFMSA confirms that it has no interest in the purchase or sale of the swap(s) other than as described in this Agreement Letter.
IV. SWAP ADVISORY COMPENSATION; REIMBURSEMENT OF
EXPENSES
For the services provided under this Agreement, PFMSA’s professional fees shall be paid as provided in Exhibit B to this Agreement and PCE shall pay expenses and fees for other services not set forth in Exhibit A as provided below.
All fees shall be due to PFMSA within thirty (30) days of the date of invoice.
1. Reimbursable Expenses
In addition to fees for services, PFMSA will be reimbursed for necessary, reasonable, and out-of-pocket expenses incurred, including, but not limited to, travel, meals, lodging, telephone, mail, and other ordinary or extraordinary costs such as for graphics, printing, document production (including as required by a subpoena or other legal document or order), data processing and computer time which are incurred by PFMSA. Upon request of PCE, documentation of such expenses will be provided.
2. Other Services
Any services which are not included in the scope of services set forth in Exhibit A of this Agreement will be subject to separate, mutually acceptable fee structures.
V. TERMS AND TERMINATION
This Agreement shall be effective from April 8, 2024 until December 31, 2024 (the “Initial Term”) and shall automatically renew for additional 6 month periods (each a “Renewal Term” and together with the Initial Term, the “Term”), unless terminated in writing by either party upon thirty (30) days written notice to the other party.
Upon any such termination, PFMSA will be paid for all services performed and costs and expenses incurred up to the termination date.
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VI. ASSIGNMENT
PFMSA shall not assign or transfer any interest in this Agreement or subcontract any of the work performed under the Agreement without the prior written consent of PCE; provided that PFMSA retains the right to enter into a sale, merger, acquisition, internal reorganization, or similar transaction involving PFMSA’s business without any such consent.
VII. INFORMATION TO BE FURNISHED TO PFMSA
All information, data, reports, and records in the possession of PCE or any third party necessary for carrying out any services to be performed under this Agreement (“Data”) shall be furnished to PFMSA. PFMSA may rely on the Data in connection with its provision of the services under this Agreement and the provider thereof shall remain solely responsible for the adequacy, accuracy and completeness of such Data.
VIII. NOTICES
All notices and other communication required under this Agreement shall be in writing and may be sent by certified mail, return receipt requested, by nationally recognized courier, with written verification of receipt, or by electronic mail. Notices shall be sent to the parties at the following addresses, or to such other address as a party may furnish to the other party:
PENINSULA CLEAN ENERGY
2075 Woodside Road
Redwood City, CA 94061
Attention: Nicholas Bijur
PFM SWAP ADVISORS LLC
1735 Market Street
42nd Floor
Philadelphia, PA 19103
Attention: George Hu, Director
IX. TITLE TRANSFER
All materials, except functioning or dynamic financial models, prepared by PFMSA pursuant exclusively to this Agreement shall be the property of PCE. Subject to the exception described above, upon termination of this Agreement, at PCE’s reasonable request no later than three (3) years after the termination of this Agreement, PFMSA shall deliver to PCE copies of any deliverables pertaining to this Agreement.
X. PFMSA’S REPRESENTATIVES
Advisory Team
The employees of PFMSA set forth below will provide the services set forth in this Agreement; provided that PFMSA may, from time to time, supplement or otherwise amend the advisory team members set forth below.
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A. Professional Staff
George Hu, Director
Brooke Pierce, Senior Swaps Consultant
Jacob Cusatis, Analyst
Changes in Advisory Team Requested by PCE
PCE has the right to request, for any reason, that PFMSA replace any member of the advisory team. Should PCE make such a request, PFMSA shall promptly suggest a substitute for approval by PCE.
XI. INSURANCE
PFMSA shall maintain insurance coverage with policy limits not less than as stated in Exhibit C.
XII. LIMITATION OF LIABILITY
Except to the extent caused by its willful misconduct, bad faith, gross negligence or reckless disregard of its obligations or duties, PFMSA shall have no liability to any party under this Agreement.
XIII. INDEPENDENT CONTRACTOR; NO THIRD-PARTY BENEFICIARY PFMSA, its employees, officers and representatives at all times shall be independent contractors and shall not be deemed to be employees, agents, partners, servants and/or joint venturers of PCE by virtue of this Agreement or any actions or services rendered under this Agreement. Nothing in this Agreement is intended or shall be construed to give any person, other than the parties hereto, their successors and permitted assigns, any legal or equitable rights, remedy or claim under or in respect of this Agreement or any provisions contained herein. In no event will PFMSA be liable for any act or omission of any third party or for any circumstances beyond PFMSA’s reasonable control including, but not limited to, fire, flood, or other natural disaster, war, riot, strike, act of terrorism, act of civil or military authority, software and/or equipment failure, computer virus, or failure or interruption of electrical, telecommunications or other utility services.
XIV. APPLICABLE LAW
This Agreement shall be construed, enforced, and administered according to the laws of the Commonwealth of Delaware. PFMSA and PCE agree that, should a disagreement arise as to the terms or enforcement of any provision of this Agreement, each party will in good faith attempt to resolve said disagreement prior to pursuing other action.
XV. ENTIRE AGREEMENT; SEVERABILITY
This Agreement represents the entire agreement between PCE and PFMSA and may not be amended or modified except in writing signed by both parties. For the sake of clarity, any 132
Rev. 07.31. 2023 - 5 -
separate agreement between PCE and an affiliate of PFMSA or any third party referred or introduced by PFMSA and/or designated by PCE shall not in any way be deemed an amendment or modification of this Agreement. The invalidity in whole or in part of any provision of this Agreement shall not void or affect the validity of any other provision.
XVI. EXECUTION; COUNTERPARTS
Each party to this Agreement represents and warrants that the person or persons signing this Agreement on behalf of such party is authorized and empowered to sign and deliver this Agreement for such party. This Agreement may be signed in any number of counterparts, each of which shall be an original and all of which when taken together shall constitute one and the same document.
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IN WITNESS WHEREOF, PCE and PFMSA have executed this Agreement as of the day and year herein above written.
PENINSULA CLEAN ENERGY
By:
Name: Shawn Marshall
Title: Chief Executive Officer
PFM SWAP ADVISORS LLC
By:
Name: George Hu
Title: Director
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EXHIBIT A
SCOPE OF SERVICES
PFM Swap Advisors LLC (as Swap Advisor and QIR)
Scope of Services Transaction Services
Consultant will serve SDCP as Municipal Advisor and designated Qualified Independent Representative (“QIR”) in the provision of general swap advisory services related to any swap-related communication, interaction or other discussion (“Swap Communication”) between SDCP and Swap Dealers (as such term is defined by the Securities and Exchange Commission (“SEC”) and the Commodity Futures Trading Commission (“CFTC”)). Consultant is obligated to comply with the applicable requirements of CFTC Regulation 17 CFR 23.450(b)(1) in providing QIR services to SDCP.
As QIR to SDCP, Consultant will make available qualified professionals to participate in discussions and other interactions with Swap Dealers as SDCP finds necessary or desirable.
Additionally, Consultant will assist SDCP with analysis of any proposals from Swap Dealers.
Consultant may assist SDCP with other swap related tasks such as helping write a swap policy or other related analysis upon SDCP’s request. Consultant will also assist SDCP, as needed, in completing the ISDA Dodd-Frank Protocols and other matters to comply with the regulatory requirements imposed under Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
Analyze and model alternative hedge structures and provide price indications; Review and comment on all hedge documentation and business terms; Assist in counterparty selection and developing terms for a request for bids (if desired); Review competitive bids and make a recommendation for award or if so determined Negotiate the pricing terms and structure with the Counterparty(s); Coordinate the closing of the transaction.
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EXHIBIT B
COMPENSATION FOR SERVICES
PFMSA will invoice for a transaction contingent flat fee of $25,000 per interest rate or commodity swap to serve as Swap Advisor on PCE’s Energy Prepayment transaction expected to be issued through the California Community Choice Financing Authority. 136
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EXHIBIT C
INSURANCE
137
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EXHIBIT D
G-42 DISCLOSURE STATEMENT
138
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07.31. 2023- 12-
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PFM FINANCIAL ADVISORS LLC
AGREEMENT FOR FINANCIAL ADVISORY SERVICES
This agreement (“Agreement”), made and entered into this 29h day of April, 2024 by and between Peninsula Clean Energy (“PCE”) and PFM Financial Advisors LLC (hereinafter called (“PFM”), sets forth the terms and conditions under which PFM shall provide services.
WHEREAS, PCE desires to obtain the services of a financial advisor to assist PCE with an energy prepayment transaction expected to be issued by the California Community Choice Financing Authority; and
WHEREAS, PFM is capable of providing the necessary financial advisory services.
NOW, THEREFORE, in consideration of the above-mentioned premises and intending to be legally bound hereby, PCE and PFM agree as follows:
I. SCOPE OF SERVICES
PFM shall provide, upon request of PCE, services related to debt issuance, as applicable and set forth in Exhibit A to this Agreement. PCE acknowledges and agrees that most tasks requested by PCE will not require all services provided for in Exhibit A and as such the specific scope of services for such task shall be limited to just those services required to complete the task. Any material changes in or additions to the scope of services described in Exhibit A shall be promptly reflected in a written supplement or amendment to this Agreement. Services provided by PFM which are not specifically referenced in the scope of services set forth in Exhibit A of this Agreement shall be completed as agreed in writing in advance between PCE and PFM. Upon the request of PCE, an affiliate of PFM or a third party referred or otherwise introduced by PFM and/or designated by PCE may agree to additional services to be provided under a separate writing, including separate scope and compensation, between PCE and such affiliate or third party.
II. WORK SCHEDULE
The services of PFM are to commence as soon as practicable after the execution of this Agreement and a request by PCE for such service.
III. REGISTERED MUNICIPAL ADVISOR; REQUIRED DISCLOSURES
1. PFM is a registered municipal advisor with the Securities and Exchange Commission (the “SEC”) and the Municipal Securities Rulemaking Board (the “MSRB”), pursuant to the Securities Exchange Act of 1934 Rule 15Ba1-2. If PCE has designated PFM as its independent registered municipal advisor (“IRMA”) for purposes of SEC Rule 15Ba1-1(d)(3)(vi) (the “IRMA exemption”), then services provided pursuant to such designation shall be the services described in Exhibit A hereto, subject to any agreed upon limitations. Verification of independence (as is required under the IRMA exemption) shall be the responsibility of such third 141
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party seeking to rely on such IRMA exemption. PFM shall have the right to review and approve in advance any representation of PFM’s role as IRMA to PCE.
2. MSRB Rules require that municipal advisors make written disclosures to their clients of all material conflicts of interest, certain legal or disciplinary events and certain regulatory requirements. Such disclosures are provided in PFM’s Disclosure Statement delivered to PCE prior to or together with this Agreement. Refer to Exhibit D.
IV. FINANCIAL ADVISORY COMPENSATION; REIMBURSEMENT OF
EXPENSES
For the services provided under this Agreement, PFM’s professional fees shall be paid as provided in Exhibit B to this Agreement and PCE shall pay expenses and fees for other services not set forth in Exhibit A as provided below.
All fees shall be due to PFM within thirty (30) days of the date of invoice.
1. Reimbursable Expenses
In addition to fees for services, PFM will be reimbursed for necessary, reasonable, and out-of-pocket expenses incurred, including, but not limited to, travel, meals, lodging, telephone, mail, and other ordinary or extraordinary costs such as for graphics, printing, document production (including as required by a subpoena or other legal document or order), data processing and computer time which are incurred by PFM. Upon request of PCE, documentation of such expenses will be provided.
2. Other Services
Any services which are not included in the scope of services set forth in Exhibit A of this Agreement will be subject to separate, mutually acceptable fee structures.
V. TERMS AND TERMINATION
This Agreement shall be effective from April 8, 2024 until December 31, 2024 (the “Initial Term”) and shall automatically renew for additional 6 month periods (each a “Renewal Term” and together with the Initial Term, the “Term”, unless terminated in writing by either party upon thirty (30) days written notice to the other party.
Upon any such termination, PFM will be paid for all services performed and costs and expenses incurred up to the termination date.
VI. ASSIGNMENT
PFM shall not assign or transfer any interest in this Agreement or subcontract any of the work performed under the Agreement without the prior written consent of PCE; provided that PFM retains the right to enter into a sale, merger, acquisition, internal reorganization, or similar transaction involving PFM’s business without any such consent. 142
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VII. INFORMATION TO BE FURNISHED TO PFM
All information, data, reports, and records in the possession of PCE or any third party necessary for carrying out any services to be performed under this Agreement (“Data”) shall be furnished to PFM. PFM may rely on the Data in connection with its provision of the services under this Agreement and the provider thereof shall remain solely responsible for the adequacy, accuracy and completeness of such Data.
VIII. NOTICES
All notices and other communication required under this Agreement shall be in writing and may be sent by certified mail, return receipt requested, by nationally recognized courier, with written verification of receipt, or by electronic mail. Notices shall be sent to the parties at the following addresses, or to such other address as a party may furnish to the other party:
PENINSULA CLEAN ENERGY
2075 Woodside Road
Redwood City, CA 94061
Attention: Nicholas Bijur
PFM FINANCIAL ADVISORS LLC
1150 S. Olive Street
10th Floor
Los Angeles, CA 90015
Attention: Managing Director
IX. TITLE TRANSFER
All materials, except functioning or dynamic financial models, prepared by PFM pursuant exclusively to this Agreement shall be the property of PCE. Subject to the exception described above, upon termination of this Agreement, at PCE’s reasonable request no later than three (3) years after the termination of this Agreement, PFM shall deliver to PCE copies of any deliverables pertaining to this Agreement.
X. PFM’S REPRESENTATIVES
Advisory Team
The employees of PFM set forth below will provide the services set forth in this Agreement; provided that PFM may, from time to time, supplement or otherwise amend the advisory team members set forth below.
A. Professional Staff
Michael Berwanger, Managing Director
James Carbone, Senior Managing Consultant
Faisal Alif, Senior Analyst
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B. Administrative and Support Staff
Kathy Nguyen, Senior Associate
Changes in Advisory Team Requested by PCE
PCE has the right to request, for any reason, that PFM replace any member of the advisory team. Should PCE make such a request, PFM shall promptly suggest a substitute for approval by PCE.
XI. INSURANCE
PFM shall maintain insurance coverage with policy limits not less than as stated in Exhibit C.
XII. LIMITATION OF LIABILITY
Except to the extent caused by its willful misconduct, bad faith, gross negligence or reckless disregard of its obligations or duties, PFM shall have no liability to any party under this Agreement.
XIII. INDEPENDENT CONTRACTOR; NO THIRD-PARTY BENEFICIARY PFM, its employees, officers and representatives at all times shall be independent contractors and shall not be deemed to be employees, agents, partners, servants and/or joint venturers of PCE by virtue of this Agreement or any actions or services rendered under this Agreement. Nothing in this Agreement is intended or shall be construed to give any person, other than the parties hereto, their successors and permitted assigns, any legal or equitable rights, remedy or claim under or in respect of this Agreement or any provisions contained herein. In no event will PFM be liable for any act or omission of any third party or for any circumstances beyond PFM’s reasonable control including, but not limited to, fire, flood, or other natural disaster, war, riot, strike, act of terrorism, act of civil or military authority, software and/or equipment failure, computer virus, or failure or interruption of electrical, telecommunications or other utility services.
XIV. APPLICABLE LAW
This Agreement shall be construed, enforced, and administered according to the laws of the Commonwealth of Delaware. PFM and PCE agree that, should a disagreement arise as to the terms or enforcement of any provision of this Agreement, each party will in good faith attempt to resolve said disagreement prior to pursuing other action.
XV. ENTIRE AGREEMENT; SEVERABILITY
This Agreement represents the entire agreement between PCE and PFM and may not be amended or modified except in writing signed by both parties. For the sake of clarity, any separate agreement between PCE and an affiliate of PFM or any third party referred or introduced by PFM 144
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and/or designated by PCE shall not in any way be deemed an amendment or modification of this Agreement. The invalidity in whole or in part of any provision of this Agreement shall not void or affect the validity of any other provision.
XVI. EXECUTION; COUNTERPARTS
Each party to this Agreement represents and warrants that the person or persons signing this Agreement on behalf of such party is authorized and empowered to sign and deliver this Agreement for such party. This Agreement may be signed in any number of counterparts, each of which shall be an original and all of which when taken together shall constitute one and the same document.
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IN WITNESS WHEREOF, PCE and PFM have executed this Agreement as of the day and year herein above written.
PENINSULA CLEAN ENERGY
By:
Name: Shawn Marshall
Title: Chief Executive Officer
PFM FINANCIAL ADVISORS LLC
By:
Name: Michael Berwanger
Title: Managing Director
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EXHIBIT A
SCOPE OF SERVICES
Supplier Evaluation and Selection
A. Drafting the RFP and incorporating any edits PCE may have after which PFM would issue the RFP.
B. Upon receipt of all the responses, PFM would summarize and present them to PCE for review.
C. PFM would provide additional feedback or context to PCE regarding the RFP responses if there is deficient information from proposers.
D. Attend and participate in meetings required to put together a working group.
E. We will help PCE evaluate and provide our independent recommendations Communications
A. Serve as the “prepay bond” subject matter expert to PCE.
B. Present at Board of Directors meetings and briefings or preparing presentation materials.
C. Create, facilitate, and attend weekly Prepayment Transaction calls after the initial distribution of documentation.
Project Management Support
A. Work with the Underwriter as well as the other parties in the working group including Bond Counsel, Disclosure Counsel, Supplier’s Counsel and Underwriter’s Counsel to ensure that the proposed timeline of issuing the prepaid bonds is acceptable to PCE.
B. Throughout the transaction, review all of the key documents, discussed below:
i. Basic Documents
Preliminary and Final Official Statements
Trust Indenture
Prepaid Energy Sales Agreement
Bond Purchase Contract
Re-Pricing Agreement
Front-End and Back-End Custodial Agreements
Continuing Disclosure Undertaking
Debt Service Account Investment Agreement
Energy Provider Guarantees
Power Supply Contract
Limited Assignment Agreement
Tax Certificate
ii. Issuer Documents
Resolutions
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Prepay Transaction Risk and Risk Mitigant Identification and Evaluation There are many benefits and considerations that must be evaluated in order to make informed decisions throughout a prepayment transaction. Throughout the prepayment transaction work, the following considerations will evolve and ad-hoc reporting and discussion will be provided by Consultant to assess prepay transaction risk and mitigating factors:
A. Maximizing Term / Savings
B. PPA Production Considerations
C. CA Regulatory Framework – Long Term Contracting
D. Segmented Structure / Re-Pricing
E. LLC Structure
Prepay Transaction Management, Technical Support and Analysis A. Provide point on technical support and analysis.
B. Independently help PCE review various PPAs and scenarios to help formulate its desired finance plan.
C. Work in tandem with the banks to ensure both parties agree on assumptions, deal specifics etc.
D. Review and provide feedback on any supplemental investor materials including investor roadshows and other marketing materials, as we have done in past transactions.
E. Provide minute-by-minute analysis during the order period, negotiate with the rating agencies regarding their fees, and communicate to PCE any fees.
F. Proactively collect and consolidate all other costs of issuance expenses.
G. On the prepayment transaction, provide the tax certificate supporting the reasonable expectation that the prepay bonds will run to term assuming at least one successful repricing.
H. Generate the FA provided certificate for tax counsel and assist PCE in issuing an RFP for a bidding agent for the reserve fund and debt service fund investment.
Post-Pricing Activities
A. Coordinating any post-closing activities, including reviewing the closing memorandum provided by the Underwriter and ensuring the timing and accurate transfer of funds.
B. Collect and verify all the invoices from the working group to provide to the Bond Trustee.
C. Timely provide a transaction report PowerPoint presentation or memo summarizing the executed prepayment transaction.
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EXHIBIT B
COMPENSATION FOR SERVICES
PFM will invoice for a transaction contingent flat fee of $300,000 to serve as Financial Advisor on PCE’s Energy Prepayment transaction expected to be issued through the California Community Choice Financing Authority.
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EXHIBIT C
INSURANCE
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EXHIBIT D
G-42 DISCLOSURE STATEMENT
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