Regulatory Packet — MCE Board of Directors, December 15, 2022

December 15, 2022
TO: MCE Board of Directors
FROM: Michael Callahan, Associate General Counsel
RE: Policy Update (Not an agenda item)
Dear Board Members:

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

I. Legislative Advocacy

a. California Legislature
Governor Newsom called a special legislative session in December this year to address windfall profits for oil refineries. This issue is outside the scope of MCE’s legislative engagement and MCE will monitor the session for potential impacts to MCE and CCAs.

b. United States Legislature
MCE has three pending earmark requests included in the Federal budget process. These earmarks were submitted by MCE’s entire Federal delegation including Senator Feinstein; Senator Padilla, Representative Huffman, and Representative Garamendi. The earmarks include: (1) $500,000 for Energy Storage at 5 critical facilities; (2) $1 million for the Healthy Homes program, to serve 200+ households; and (3) $2 million for up to 385 Level 2 Electric Vehicle Charging Stations. Each earmark is included in the federal spending package that is currently being debated. The present deadline to pass a budget is December 16. It is likely there will be another continuing resolution to push this deadline back. MCE has been advised by our lobbyists that despite the change in control of the House, earmark requests will stay in the package. MCE will continue to track the budget process and the associated earmarks.

MCE Empowering
Our Clean
Energy Future

CONTRA COSTA I MARIN I NAPA I SOLANO

II. Federal Advocacy

a. United States Department of the Treasury

On November 4, 2022 MCE submitted comments to the U.S. Department of the Treasury (Treasury) requesting clarification and guidance on specific clean energy-related provisions in the Inflation Reduction Act (IRA). MCE commented on a number of provisions that define a tax-exempt-entity’s and a clean energy project’s eligibility for certain tax credits applicable to clean energy generation projects. Topics included clarification on the applicability of direct tax credit benefits for local government agencies, such as MCE, prevailing wage and apprenticeship requirements, and attributes for manufactured project materials necessary to qualify for additional manufacturing tax credits.

MCE expects Treasury to issue formal guidance and regulations over the coming months related to clean energy IRA provisions. MCE is continuously assessing clean energy-related updates from Treasury and evaluating the need for supplemental comment.

MCE’s advocacy is focused on identifying opportunities to access tax credits to support generation projects and programs either owned and administered directly by MCE or by third-party developers and administrators to help accelerate clean energy project development and bring down costs for customers.

III. California Public Utilities Commission

a. Integrated Resource Plan
As required by Public Utilities Code (Code) Section 452.54, on November 1, 2022, MCE filed its California Public Utilities Commission (Commission or CPUC) Integrated Resource Plan (Compliance IRP) with the Commission. MCE’s biennial Compliance IRP describes MCE’s mid- and long-term resource planning and reflects MCE’s internal goals and targets and the Commission’s updated requirements to meet the state’s reliability and greenhouse gas (GHG) emissions goals.

MCE received prior Board approval of its Compliance IRP on October 20, 2022.

Compliance IRP Requirements:

In this IRP cycle, the Commission directed all Load Serving Entities (LSE) to develop two IRP portfolios: one that is consistent with a statewide GHG emission limit for the electric sector of 38 million metric tons (MMT) of emissions by 2030 and 30 MMT by 2035 (30 MMT portfolio); and a second more aggressive portfolio that meets or goes below the limit of 30 MMT by 2030 and 25 MMT by 2035 (25 MMT portfolio). The Commission allowed LSEs to provide a single portfolio that achieved both targets if the LSE prefers a lower-emissions portfolio. MCE’s portfolio achieved this more aggressive target, and thus MCE’s Compliance IRP includes a single, lower-emissions portfolio referred to as the Preferred Conforming Portfolio (PCP).

MCE’s PCP achieves both the 2030 MMT and 25 MMT targets and meets all CPUC-assigned benchmarks, energy requirements, and reliability metrics throughout the planning period.

MCE’s PCP includes plans for significant capacity additions of new renewable and storage resources by 2035 to support achievement of MCE’s renewable and GHG-free energy goals, while contributing to system reliability in a responsible manner.

The resource portfolio includes a mix of existing and new resources strategically integrated to adhere to MCE’s policy to achieve at least 85% renewable energy by 2035.

In fact, MCE’s PCP results in approximately 87% renewable energy in 2035, the vast majority of which will be secured under long-term contracts. Approximately 1,100 MW of MCE’s PCP is composed of new resources, reflecting MCE’s active role in the State’s development of new renewable and storage resources. Additionally, MCE’s short- and long- duration storage, renewable baseload procurement, and its capacity-only resources will help maintain MCE’s critical role in supporting the State’s need for reliability and renewable integration.

All LSE Compliance IRPs are currently under review by the Commission. As in prior IRP cycles, the Commission will assess each IRP for compliance with all CPUC-requirements and aggregate the individual LSE portfolios to determine whether the LSEs are on track to meet state reliability and GHG-reduction needs. Staff expects the CPUC to issue a ruling on MCE’s Compliance IRP in mid-2023.
b. Transportation Electrification

On November 17, the Commission published a Decision on Transportation Electrification (TE) Policy and Investment which concluded 3 years of stakeholder discussion on the future of ratepayer-funded TE programs. The Decision approved a third party administered, statewide TE infrastructure rebate program with a budget of $1 billion for 2025 – 2029. Rebates are limited to EV charging equipment at multi-dwelling units (MUDs), MUD-serving locations and the medium- and heavy-duty sector (MDHD). 65% of the rebate funding is reserved for underserved communities and Equity customers qualify for higher rebates (the exact incentive amount is to be determined in workshops).

Most relevant to CCAs, the Decision also approved the “Locally Invested Transportation Electrification” (LITE) pilot program. The LITE pilots are Equity-based, locally tailored pilot programs to test new and innovative TE infrastructure strategies for MUDs and the MDHD sector. They are funded at $4 million per pilot proposal for a three-year implementation period starting in early 2025. Importantly, only CCAs and community-based organizations (CBOs) can participate in the competitive solicitation to receive funding for the LITE pilots. The solicitation is expected to be released in Q4 2023.

c. Self-Generation Incentive Program (SGIP)
The statewide, ratepayer-funded Self-Generation Incentive Program (SGIP) is a core driver for the installation of behind-the-meter (BTM) energy storage systems (ESS) in California. On October 26, the Commission published a Ruling in the SGIP proceeding (R.20-05-012) seeking comments on improving the SGIP’s Equity outcomes and Assembly Bill (AB) 209 implementation. AB 209 allocated an additional $900 Million to the SGIP starting on July 1, 2023. The funding is targeted at the installation of ESS for residential customers only with a 70% budget carve out for low-income customers. Notably, for the first time ever, SGIP will provide incentives for combined solar + storage system to low-income customers as well.

MCE led a Joint CCA working group and filed opening comments on the Ruling on December 2. The Joint CCAs’ comments were focused on modifying SGIP rules and requirements to enable greater participation of low-income customers under the program.
a. Enhanced Power Safety Settings (EPSS)
On July 11, MCE joined Pioneer Community Energy, Sonoma Clean Power Authority, East Bay Community Energy, and Rural County Representatives of California (Joint Parties) in filing a motion requesting the CPUC consider adopting Fast Trip program rules in the de-energization rulemaking. Fast Trip programs are intended to reduce wildfire risk by significantly increasing the sensitivity of protective devices and equipment that trigger automatic outages when a fault is detected. From January to October of 2022, PG&E’s Enhanced Power Safety Settings (EPSS) Program left 374,329 customers across Marin, Napa, Solano, and Contra Costa counties without power for an average of 5.6 hours.

These outages affected 747 schools, 39 hospitals, and 20,316 customers who depend on power to charge medical devices. The IOUs’ Fast Trip programs impose significant potential risks to public health, safety, and welfare. Despite these risks, the Fast Trip programs are not currently overseen or regulated by the CPUC.

After filing the motion, the Joint Parties and local government representatives including Director Rice and Napa County Supervisor Dillon, met with the offices of all five CPUC Commissioners, as well as the Office of Energy Infrastructure Safety. In these meetings, MCE and other stakeholder representatives emphasized the impact this program has on communities in PG&E’s service area. The group highlighted the harm to areas that face repeated extended outages without notification, the compounding risk created by landline telecommunication service being disrupted by outages, and the concern of severe wind events causing widespread trips across the service-area with an insufficient workforce to timely restore power. In November, the Joint Parties gathered support for a letter from state legislators to the CPUC urging action on this issue. In response, PG&E provided its own letter to legislators indicating the program is necessary and effective at reducing fire risk. The CPUC also provided a letter to legislators indicating it is working with the Office of Energy Infrustructure and Safety to address impacts to communities from Fast Trip program impacts and is continuing to deliberate on this issue. MCE will remain engaged on this issue and support impacted local government advocacy.

Recommendation: Information only. No action required.

OCTOBER FILINGS

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric (U 39 E)
Proposing Framework for Substation Microgrid
Solutions to Mitigate Public Safety Power Shutoffs.

Application 21-06-022
(Filed June 30, 2021)

OPENING COMMENTS OF JOINT COMMUNITY CHOICE AGGREGATORS ON

PROPOSED DECISION ADOPTING A FRAMEWORK FOR SUBSTATION

MICROGRID RESILIENCY SOLUTIONS TO MITIGATE PUBLIC SAFETY POWER

SHUTOFFS FOR PACIFIC GAS AND ELECTRIC COMPANY
Neal Reardon
Director, Regulatory Affairs

SONOMA CLEAN POWER AUTHORITY
431 E St. Santa Rosa, CA, 95404
Email: [email protected]
Aisha Cissna
Regulatory and Legislative Policy Manager

REDWOOD COAST ENERGY AUTHORITY
633 Third Street Eureka, CA 95501
Telephone: 707-269-1700
E-mail: [email protected]
Jana Kopyciok-Lande
Strategic Policy Manager

MARIN CLEAN ENERGY
1125 Tamalpais Ave San Rafael, CA 94901
Telephone: (415) 464-6044
Email: [email protected]
Mad Stano
Policy Counsel

MARIN CLEAN ENERGY
1125 Tamalpais Ave San Rafael, CA 94901
Telephone: (415) 464-6024
Email: [email protected]
October 19, 2022
Opening PD Comments of Joint CCAs
i
Subject Index
I. INTRODUCTION ................................................................................................................. 1 II. The Commission Must Direct PG&E to Publish the 10-Year Historic Look Back Analysis on an Annual Basis. ....................................................................................................... 3 III. The Commission Must Clearly Outline the Timing for PG&E to File Advice Letters or Applications for Microgrids at HLA Identified Candidate Substations.................................. 4 IV. The Commission Should Adopt the “Alternative Prioritization Method” for Identifying Candidate Substations and Direct PG&E to File an Advice Letter to Propose a Specific Threshold. ...................................................................................................................................... 6 V. The Commission Should Order Greater Clarification for Prioritizing Medical Baseline Customers. ..................................................................................................................................... 8 VI. The Commission Should Limit the Number of Single-Season Microgrids PG&E Can Procure at an Individual Substation;.......................................................................................... 9 VII. The Commission Must Clarify a Clean Substation Microgrid Project Developed Pursuant to this Framework Will Not Impact a Customer's Choice of, or Exerpience with, their Load-Serving Entity………………………...……………………………………………10 VIII. CONCLUSION…………………………………………………………………………...10
Opening PD Comments of Joint CCAs
ii
Table of Authorities
Commission Decisions
D.21-01-018 ………………………………………………………………………4, 5, 8, 9, 10
Statutes
Senate Bill 1339 (2018)……………….…………………………………………….................4 Opening Comments of Joint CCAs
1 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric (U 39 E)
Proposing Framework for Substation Microgrid
Solutions to Mitigate Public Safety Power Shutoffs.

Application 21-06-022
(Filed June 30, 2021)

OPENING COMMENTS OF JOINT COMMUNITY CHOICE AGGREGATORS ON

PROPOSED DECISION ADOPTING A FRAMEWORK FOR SUBSTATION

MICROGRID RESILIENCY SOLUTIONS TO MITIGATE PUBLIC SAFETY POWER

SHUTOFFS FOR PACIFIC GAS AND ELECTRIC COMPANY
I. INTRODUCTION
Pursuant to Rule 14.3 of the Rules of Practice and Procedure of the California Public Utilities Commission (“Commission” or “CPUC”), Marin Clean Energy (“MCE”), Sonoma Clean Power Authority (“SCP”), and Redwood Coast Energy Authority (“RCEA”)1 respectfully submit these Opening Comments on the Proposed Decision Adopting a Framework for Substation Microgrid Resiliency Solutions to Mitigate Public Safety Power Shutoffs for Pacific Gas & Electric Company (“Proposed Decision” or “PD”) mailed on September 29, 2022. The Joint Community Choice Aggregators2 (“CCAs”) support the Commission adopting the Proposed Decision with additional refinements. The Joint CCAs support and appreciate the Commission’s thoughtful and 1 RCEA filed its Motion for Party Status on October 19, 2022, and awaits the ruling on its party status.
2 MCE, SCP, and RCEA submit these comments jointly as “Joint Community Choice Aggregators” or “Joint CCAs.”
Opening Comments of Joint CCAs
2 balanced approach to implementing a detailed framework for clean substation microgrid resiliency solutions to mitigate public safety power shutoffs (“PSPS”) for Pacific Gas and Electric Company (“PG&E”). The Joint CCAs especially support the transition to clean substation microgrids under the proposed emission standards.

The Joint CCAs submit the following modifications to the PD that will ensure PG&E and the Commission achieve the vital public interest objectives of “spurring development of clean resiliency technologies to mitigate and ultimately reduce greenhouse gas emissions during public safety power shutoffs.”3
• The Commission must direct PG&E to publish the 10-Year Historic Look Back Analysis4 (“HLA”) on an annual basis.
• The Commission must clearly outline the timing for PG&E to file Advice Letters or Applications for microgrids at HLA identified candidate substations. • The Commission should adopt the “Alternative Prioritization Method” for identifying candidate substations and direct PG&E to file an Advice Letter to propose a specific threshold.
• The Commission should order greater clarification for prioritizing medical baseline customers.
• The Commission Should Limit the Number of Single-Season Microgrids PG&E Can Procure at an Individual Substation.
3 PD at 2.
4 PD at 11.

Opening Comments of Joint CCAs
3 • The Commission must clarify a clean substation microgrid project developed pursuant to this framework5 will not impact a customer’s choice of, or experience with, their load-serving entity.

II. The Commission Must Direct PG&E to Publish the 10-Year Historic Look Back Analysis on an Annual Basis.

The Joint CCAs agree with the Commission that the 10-Year HLA will analyze relevant weather and environmental data in a manner that supports well-reasoned selection of PSPS impacted substations.6 However, the PD makes an error in law does not clearly state how frequently PG&E must run the HLA. The Joint CCAs fear the ambiguity of the PD jeopardizes the informed public oversight and stakeholder engagement required7 to ensure the success of this framework.

PG&E stated in its testimony it plans to update the data inputs for the HLA on an “annual basis,”8 and “would use the outputs of this framework to determine whether to propose specific substation-level microgrid projects for PSPS mitigation and would then submit those specific projects.”9 The Joint CCAs interpret this language as stating PG&E’s intent to both update the supporting methodological inputs and run the HLA for the purposes of selecting potential substation sites on an annual basis. However, as currently written, the Proposed Decision does not mandate PG&E to do so.
5 “Framework” used in this document to reference a Framework for Substation Microgrid Resiliency Solutions to Mitigate Public Safety Power Shutoffs for Pacific Gas & Electric Company. 6
PD at 15.
7 PD at 15 (explaining the HLA will “enable PG&E to utilize more reliable data and modeling that will in turn inform the Commission and stakeholders with better information…). 8 Exh. PGE-001 at 2-9.
9 Exh. PGE-001 at 2-9.

Opening Comments of Joint CCAs
4 To prevent any ambiguity or legal error, the Joint CCAs recommend that the Commission include a clear order in the final Decision that PG&E must update, run and file the HLA in a publicly available manner with the Commission on an annual basis. Many other parties and the Commission10 itself recognized the collaborative public process required for an optimal HLA.11 Many stakeholders possess vital information to update methodologies and considerations for the HLA. For the Joint CCAs specifically, information from an annual HLA is essential for planning to best serve its potentially impacted customers. As changing climate will continue to impact the scope, number, and duration of expected events – effective solutions cannot be developed using static data. Hence, the Joint CCAs recommend the Commission direct PG&E to run and publish the HLA on an annual basis.

III. The Commission Must Clearly Outline the Timing for PG&E to File Advice Letters or Applications for Microgrids at HLA Identified Candidate Substations.

OP 2 and OP 5 of the PD currently state that PG&E shall file single-season Advice Letters (“AL”) or multi-season Applications for candidate substations12 when “reasonable.”13 The PD makes a legal error and does not define “reasonable” in this instance. The PD instead grants PG&E the deference to unilaterally determine it. The Joint CCAs disagree and recommend the Commission require the filing of Advice Letters or Applications according to a designated timeline and the framework criteria. Absent this direction, PG&E is authorized to endlessly study candidate 10 PD at 17 and 18 (directing PG&E to work with scientific experts to update HLA inputs with emerging scientific information).
11 See e.g. Exh. TURN-001, p. 9; Exh. PAO-001, p. 5-3; Exh. CESA-001, p. 11 (stating comments on methodological approaches).
12 Candidate substations are defined as those meeting or exceeding the “10/100 Threshold Methodology,” i.e. substations that had more than 10 PSPS events in 10 years in the HLA, as well as more than 100 safe-to-energize (“STE”) customers. The Joint CCAs recommend revising the threshold in Section IV below.
13 PD at 66-67 (OP 2;5).

Opening Comments of Joint CCAs
5 substation sites without taking the necessary actions to develop them in accordance with Decision (“D.”) 21-01-018 and Senate Bill 1339.14
The Joint CCAs understand the clean substation development framework outlined in the PD to include the following implementation steps:
1) PG&E updates and runs the HLA on an annual basis to identify candidate substations; 2) PG&E conducts the alternatives analysis to analyze if alternative mitigation options are already being considered;
3) If candidate substations remain after the alternative analysis, PG&E runs requests for offers (“RFOs”) for the identified candidate substations.15 Without additional direction, PG&E may run the HLA and alternatives analysis, identify candidate substations but choose not to pursue solicitation and/or file authorizing Advice Letters or Applications. Furthermore, the Joint CCAs believe that there must be an important distinction in the timing of the submission of single-season Advice Letters versus multi-season Applications.

The Joint CCAs specifically recommend the following:
• Single-Season Microgrids: The Commission must direct PG&E to file a Tier 2 Advice Letter at the conclusion of an RFO (after Step 3 above), regardless of whether the RFO resulted in the signing of a contract or not. The information gathered through the HLA, alternatives analysis and RFO process is beneficial to the public and critical to advancing D.21-01-018 regardless of whether it produces signed contracts. • Multi-Season Microgrids: The Commission must direct PG&E to file an Application anytime the HLA and alternatives analysis identify candidate substations (after Step 2 14 D.21-01-018 at 3-4 (requiring the policy framework “facilitating the commercialization of microgrids and related resiliency strategies”).
15 PD at 33-37.

Opening Comments of Joint CCAs
6 above),16 but before issuing an RFO. If the HLA and alternative analysis identify substations that are candidates for multi-season microgrids, PG&E must be required to file an Application to assess the procurement of a clean microgrid at the candidate substation.

This Application must include a description of all substations identified as candidate substations.

To meaningfully support “keeping the lights on to preserve community continuity - one of the Commission’s ongoing priority objectives to protect the public health, welfare, and safety of all Californians,” the Commission must direct PG&E to act on this framework when it satisfies its substantive and procedural requirements.17 Without this direction, the Commission risks ordering a potentially expensive study of microgrid solutions of little value to ratepayers burdened by the ongoing negative impacts of PSPS events.

IV. The Commission Should Adopt the “Alternative Prioritization Method” for Identifying Candidate Substations and Direct PG&E to File an Advice Letter to Propose a Specific Threshold.

The Commission should adopt the widely supported “Alternative Prioritization Method” for identifying candidate substations.18 The Joint CCAs support this more complete and data-driven assessment of clean substation microgrid site selection. The Joint CCAs and many other parties, including PG&E, detailed support for elements of the Alternative Prioritization Method in Opening and Reply Briefs in this proceeding.19 Further, the Joint CCAs and many other parties 16 PD at 12 (10/100 threshold as proposed in PD. Joint CCAs recommend revising threshold in Section 4).
17 PD at 2.
18 Exh. PGE-005, p. 2-2.
19 See e.g. Joint CCAs Opening Brief at 5-7; California Energy Storage Alliance Opening Brief at 2; PG&E Opening Brief at 44; The Utility Reform Network Opening Brief at 13; Cal Advocates Testimony at 3-3; PD at 14 (“parties tended to favor” Alternative Prioritization Methodology).

Opening Comments of Joint CCAs
7 identified deficiencies in the competing “10 out of 100+ Threshold Methodology”20 that remain unaddressed by the PD.
21 The Joint CCAs continue to be concerned about the 10 out of 100+ threshold for the following reasons.

First and foremost, it is legally inadequate that the 10 out of 100+ threshold only considers the frequency of PSPS events but not their duration or impact on communities. The Joint CCAs find the human scale of PSPS events important information for substation selection and fear the impacts if entirely ignored. Second, PG&E arbitrarily set the “10 events in 10 years” threshold without adequate stakeholder input and feedback. The PD now judges this threshold per se reasonable22 without providing any explanation.

Instead, the PD states two key concerns with the Alternative Prioritization Method.23 The Commission first stated the Alternative Prioritization Method was inadequate because it lacked a clear threshold and described the understandable advantages of a bright-line rule. 24 The Joint
CCAs agree that threshold clarity and the ease of implementation of the framework are valuable factors for consideration. However, the Joint CCAs don’t find clarity alone adequate evidence of the 10 out of 100+ threshold’s “reasonableness.” Additionally, the Joint CCAs proposed an Advice Letter process to establish clear, scientifically supported, and actionable thresholds for the Alternative Prioritization Methodology in its Opening Brief.25 20 Under the “10 out of 100+ Threshold Methodology,” or “10 or more threshold” substations are identified as candidate substations if they experienced more than 10 PSPS events over 10 years in the HLA, while also serving more than 100 STE customers. 21 PD at 12.
22 PD at 15-16.
23 PD at 14.
24 PD at 14. 25 Joint CCAs Opening Brief at 6-7 (“The Joint CCAs request the Commission authorize the appropriate public oversight over the specific ranking methodology and threshold setting for candidate substations via an Advice Letter process…”).

Opening Comments of Joint CCAs
8 Second, the Commission feared that the Alternative Prioritization Method would skew substation candidate sites toward urban communities at the expense of rural communities.26 Joint CCAs respect this concern as the load-serving entity to many rural and urban communities, but similarly don’t find it persuasive evidence of the 10 out of 100+ threshold’s “reasonableness.” The Commission could, for example, mitigate the associated risk to rural communities by requiring PG&E to apply per capita considerations to its consequence score methodology or threshold. The Commission could appropriately balance relevant interests and the requirements of D.21-01-018 by developing a more holistic threshold through an Advice Letter process.27 In summary, the Joint CCAs request the Commission reconsider and adopt the Alternative Prioritization Methodology in the final Decision. The Joint CCAs also recommend that the Commission direct PG&E to file a Tier 2 Advice Letter to establish a publicly vetted and scientifically grounded threshold for the Alternative Prioritization Methodology.

V. The Commission Should Order Greater Clarification for Prioritizing Medical Baseline Customers.

The Joint CCAs strongly support the Commission’s adoption of TURN’s recommendation to prioritize medical baseline customers in substation site selection.28 The Joint CCAs request the Commission order greater clarification to avoid legal errors on how PG&E must prioritize medical baseline customers. As TURN and the Commission outlined, medical baseline customers are disproportionately and severely impacted by PSPS events in life-threatening ways. 29 The
Commission should correspondingly ensure the clear and transparent protection of medical baseline customers. The PD states PG&E must “further prioritize[] projects that serve medical 26 PD at 15.
27 Joint CCAs Opening Brief at 6-7. 28 PD at 16.
29 TURN Opening Brief at 12.

Opening Comments of Joint CCAs
9 baseline customers…” but does not describe how.30 Does that mean a substation with 10 events and 1000 medical baseline customers gets more weight than a substation with 11 events and 500 medical baseline customers? Or does this prioritization mean, if all other criteria are comparable, PG&E should select the site with more medical baseline customers? The Joint CCAs request the Commission direct PG&E to, at a minimum, document the number of medical baseline customers for each candidate substation and explain how it prioritized specific sites based on this information.

VI. The Commission Should Limit the Number of Single-Season Microgrids PG&E Can Procure at an Individual Substation.

In accordance with D.21-01-018, the Commission must limit the number of single-season microgrids PG&E can procure at an individual substation. D.21-01-018 requires “advancing a process for transitioning to clean temporary generation after 2021[.]”31 The Joint CCAs fear that the PD as written unintentionally permits PG&E to procure consecutive single-season microgrids without reasonable legal limits.32 In addition to the different levels of stakeholder engagement and public oversight on single and multi-season microgrids, the Joint CCAs elevate extreme concerns at the potential public health impacts of unlimited single-season microgrid procurement. The PD applies PG&E’s proposed emissions standard exclusively to multi-season and not single-season microgrids.33 Unlimited single-season microgrid procurement could undermine the entire purpose of this proceeding by resulting in greater use of diesel generation and associated negative health impacts with no clean substations development even when justified by PG&E’s analysis.
30 PD at 67 (OP 5).
31 D.21-01-018 at 93; Appendix A.
32 PD at 30-36 (discussing procurement requirements and failing to include single-season procurement limits).
33 PD at 59. See also PD at 22-24.

Opening Comments of Joint CCAs
10 The Commission must clarify PG&E may not use the single-season microgrid procurement process to avoid the necessary requirements of multi-season microgrid procurement processes.

The Joint CCAs request the Commission apply common-sense limits on the extended use of diesel for PSPS mitigation in compliance with D.21-01-018.34 The Joint CCAs thus request the Commission order PG&E to file an Application to consider a multi-season microgrid for any substation for which it has requested a single-season microgrid via Tier 2 Advice Letter process during three consecutive years.

VII. The Commission Must Clarify a Clean Substation Microgrid Project Developed Pursuant to this Framework Will Not Impact a Customer’s Choice of, or Experience with, their Load-Serving Entity
The Joint CCAs strongly support and appreciate the Commission requiring PG&E consult and coordinate with CCAs on multi-season microgrid procurement and their impacts on CCA customers.35 The Joint CCAs agree that this consultation is reasonable and necessary to the success of this framework. As recommended in briefing, the Joint CCAs request the PD clarify the framework and subsequent procurements do not alter customer choice and protections for CCA customers.36 The Commission, PG&E and no party suggest otherwise in the record of this proceeding. As stated in its Opening Brief, PG&E and Joint CCAs do not interpret the framework to authorize altering existing rights, billing practices and service protections for CCA customers.
37 Due to the lack of controversy on this issue among parties and the legal risks of ambiguity to CCA customers, the Joint CCAs request the Commission clarify the framework and 34 D.21-01-018 at Appendix A, A-2 (“Given the particularly high emissions of harmful air pollutants from Tier 2 diesel engines and conventional diesel fuel, the Commission expects a utility to minimize its use of Tier 2 diesel—and use alternative fuels”). 35 PD at 39; 61; 65; 68.
36 Joint CCAs Opening Brief at 10.
37 Id.; Exh. Joint CCAs-001 at 1-4.

Opening Comments of Joint CCAs
11 its subsequent projects do not impact a customer’s choice or experience of their Load-Serving Entity.

VIII. CONCLUSION
• The Commission must direct PG&E to publish the 10-Year Historic Look Back Analysis on an annual basis.
• The Commission must clearly outline the timing for PG&E to file Advice Letters or Applications for microgrids at HLA identified candidate substations. • The Commission should adopt the “Alternative Prioritization Method” for identifying candidate substations and direct PG&E to file an Advice Letter to propose a specific threshold.
• The Commission should order greater clarification for prioritizing medical baseline customers.
• The Commission should limit the number of single-season microgrids PG&E can procure at an individual substation.
• The Commission must clarify a clean substation microgrid project developed pursuant to this Framework will not impact a customer’s choice of, or experience with, their Load-Serving Entity.

The Joint CCAs thank Commissioner Shiroma, Administrative Law Judge Rizzo and all parties for the robust discussion on clean substation microgrids and the commitment to advancing a cleaner and safer California in this PD.

Opening Comments of Joint CCAs
12 Dated: October 19, 2022. Respectfully submitted,
/s/ Jana Kopyciok-Lande
Jana Kopyciok-Lande
Strategic Policy Manager

MARIN CLEAN ENERGY
1125 Tamalpais Ave San Rafael, CA 94901
Telephone: (415) 464-6044
Email: [email protected]
/s/ Aisha Cissna
Aisha Cissna
Regulatory and Legislative Policy Manager

REDWOOD COAST ENERGY AUTHORITY
633 Third Street Eureka, CA 95501
Telephone: 707-269-1700
E-mail: [email protected]
/s/ Neal Reardon
Neal Reardon
Director, Regulatory Affairs
Sonoma Clean Power Authority
431 E Street
Santa Rosa, CA 95404
E-mail: [email protected]
/s/ Mad Stano
Mad Stano
Policy Counsel

MARIN CLEAN ENERGY
1125 Tamalpais Avenue
San Rafael, CA 94901
Telephone: (415) 464-6024
Email: [email protected]
Opening Comments of Joint CCAs
13 Appendix
Proposed Revisions to Conclusion of Law & Ordering Paragraphs Findings of Fact
(Revised) 6. The 10-year HLA uses a threshold identified pursuant to the Alternative Prioritization Method and a Tier 2 Advice Letter filed by PG&E as a method for selecting a substation microgrid.

Conclusions of Law
(Revised) 2. It is reasonable to require PG&E to annually use and publish a 10-year HLA to identify and prioritize PG&E substations that are highest risk for PSPS. (Revised) 6. It is reasonable to require PG&E to prioritize and document the number of medical baseline customers who are served by substations identified in its 10-year HLA analysis. (New) 26. It is reasonable to prohibit PG&E from filing no more than 3 consecutive single-season microgrids at an individual substation.

Ordering Paragraphs
(Revised) 1. Pacific Gas and Electric Company shall file the relevant results from each new iteration of its 10-year Historical Lookback Analysis, when reasonably available, on an annual basis via Compliance Filing with the Energy Division.
(New) 2. Pacific Gas and Electric Company shall file a Tier 2 Advice for any single-season candidate substations identified pursuant to the 10-Year Historical Lookback Analysis and alternatives analyses. Pacific Gas and Electric Company shall file an Application for any multi-season candidate substations identified pursuant to the 10-Year Historical Lookback Analysis and alternatives analyses.
(New) 3. Pacific Gas and Electric Company shall file a Tier 2 Advice Letter to propose a specific threshold for the Alternative Prioritization Method for identifying candidate substation within 90 days of the issuance of this Decision.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Application of Pacific Gas and Electric Company
for Adoption of Electric Revenue Requirements
and Rates Associated with its 2023 Energy
Resource Recovery Account (ERRA) and
Generation Non-Bypassable Charges Forecast and
Greenhouse Gas Forecast Revenue Return and
Reconciliation. (U39E).

Application 22-05-029
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S

REPLY BRIEF
Evelyn Kahl
General Counsel and Director of Policy
Willie Calvin
Regulatory Case Manager

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
One Concord Center
2300 Clayton Road, Suite 1150
Concord, CA 94520
Telephone: (415) 254-5454
E-mail: [email protected]
Tim Lindl
Nikhil Vijaykar

KEYES & FOX LLP
580 California Street, 12th Floor
San Francisco, CA 94104
Telephone: (510) 314-8385
E-mail: [email protected]
[email protected]
On behalf of
California Community Choice Association
October 21, 2022
FILED
10/21/22
04:59 PM
A2205029
i

TABLE OF CONTENTS
I. PG&E MUST IMPLEMENT PCIA RATE CREDITS FOR BUNDLED AND UNBUNDLED CUSTOMERS ON A FORECAST BASIS...............................................4 A. D.18-10-019 Rendered a PCIA Rate Floor Obsolete. .............................................4 B. Timely Recovery of Costs Does Not Permit PG&E to Overcharge Customers. ...............................................................................................................5 II. CONCLUSION ...................................................................................................................8 ii

TABLE OF AUTHORITIES
Statutes
Cal. Pub. Util. Code § 451...............................................................................................................2 Cal. Pub. Util. Code § 453(c) ..........................................................................................................2 Cal. Pub. Util. Code § 454.5(d)(3) ..................................................................................................5 Commission Decisions
D.11-10-012.....................................................................................................................................6 D.18-10-019.........................................................................................................................2, 3, 4, 7 D.19-10-001.....................................................................................................................................4 D.20-02-047.....................................................................................................................................8 D.21-05-030.............................................................................................................................2, 4, 7 D.22-02-002.....................................................................................................................................8 Commission Rules of Practice and Procedure
Rule 13.12........................................................................................................................................1 iii

SUMMARY OF RECOMMENDATIONS
• Reject Pacific Gas and Electric Company’s (PG&E) position and adopt Power Charge Indifference Adjustment (PCIA) rate credits for vintages where the forecasted, cumulative indifference amount is negative.
• Enact the procedural recommendation in D.20-02-047 to create a more permanent crediting framework for banked renewable energy credits in the Power Charge Indifference Adjustment rulemaking, R.17-06-026.
• Adopt CalCCA’s uncontested recommendations to adjust PG&E’s revenue requirement to address (1) the sale of PG&E’s San Francisco headquarters, (2) the correct on-peak and off-peak load weights, and (3) Witness Shuey’s accounting methodology to reflect PG&E’s Modified Cost Allocation Mechanism procurement.
• Adopt CalCCA’s uncontested recommendation to transfer the final year of Energy Resource Recovery Account-PCIA Financing Subaccount amortization to the vintage 2020 consistent with Commission direction in D.22-02-002.

BEFORE THE PUBLIC UTILITIES COMMISSION

Application 22-05-029
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S

REPLY BRIEF
Pursuant to Rule 13.12 of the Rules of Practice and Procedure of the California Public Utilities Commission (Commission) and the July 25, 2022 Scoping Memo and Ruling setting the schedule for this proceeding,1 California Community Choice Association2 (CalCCA) hereby submits this Reply Brief regarding the Application of Pacific Gas and Electric Company (PG&E) for Adoption of Electric Revenue Requirements and Rates Associated with its 2023 Energy Resource Recovery Account (ERRA) and Generation Non-Bypassable Charges Forecast and Greenhouse Gas Forecast Revenue Return and Reconciliation. (U39E) (Application). 3 1 Application (A.) 22-05-029, Assigned Commissioner’s Scoping Memo and Ruling (August 4, 2022) (Scoping Ruling).
2 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Desert Community Energy, East Bay Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Choice Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy. 3 A.22-05-029, Application of Pacific Gas and Electric Company for Adoption of Electric Revenue Requirements and Rates Associated with its 2023 Energy Resource Recovery Account and Generation Non- 2 CalCCA Witness Shuey’s prediction has come true;4 PG&E’s October 17, 2022 updated testimony (October Update) forecasts negative cumulative indifference amounts for four vintages:
2009, 2021, 2022, and 2023.5 That means PG&E’s refusal to follow Commission precedent, the law and sound ratemaking policy regarding the treatment of negative forecast indifference amounts will deny PCIA rate credits to both bundled (2023 vintage) and unbundled (2009, 2021 and 2022 vintages) customers.6
PG&E’s proposal to set a PCIA rate floor would intentionally overcharge customers in 2023 on a forecast basis.
7 It would result in PG&E setting PCIA rates differently between vintages, using the forecasted indifference amounts for customers in twelve of its vintages (the Legacy and 2010-2020 vintages) but not for customers in its other four vintages. 8 It would also result in PG&E
setting PCIA rates differently than Southern California Edison, which plans to implement its nine forecasted, negative cumulative indifference amounts in a lawful manner.9 PG&E’s proposal neither complies with D.18-10-019 nor the Commission’s indifference framework, which has eliminated all limits on PCIA rate changes: the rate floor (D.18-10-019) and the rate cap (D.21- 05-030).10 It violates Public Utilities Code §451’s requirement for just and reasonable rates and §453(c)’s prohibition against unjustifiably discriminatory ratemaking. 11 Direct Access Customer
Bypassable Charges Forecast and Greenhouse Gas Forecast Revenue Return and Reconciliation (May 31, 2022) (Application).
4 Exh. CalCCA-01 at 27:5-30:16.
5 Exh. PGE-4 at 22-28.
6 CalCCA Opening Brief at 19-20.
7 Id. at 8-15.
8 Id. at 15-16.
9 Id.
10 Id. at 12-13.
11 Id. at 15-19.
3 Coalition’s (DACC) Opening Brief agrees with CalCCA’s position,12 further underscoring the fact that to date no party or utility in the state except PG&E agrees with PG&E’s position.

PG&E’s opening brief reads restrictions into D.18-10-019 that do not exist. It offers no sound policy justification for the proposal. The utility appears to mistrust the Commission-approved Portfolio Allocation Balancing Account (PABA) true-up mechanism for rate credits, which has worked well for rate charges, without providing any evidence that mechanism is unfit for the task of addressing rate credits. As a potential justification for its proposal, PG&E points to the lack of what might be called a “PABA trigger” as a risk to its shareholders; but it ignores how customers carry the same risk, and they carry that risk without the access to debt and equity markets that PG&E enjoys. The brief requests authorization for the utility to create yet another balancing account in order to enact the proposal. None of that complexity is necessary. Only one balancing account is needed, and that is the already existing and functioning PABA.

PG&E should be required to implement rate credits for all vintages where cumulative forecasted negative indifference amounts exist. Beyond this contested Scoping Issue 5, and the question of whether a Commission decision in this case can determine the proceeding in which a permanent banked REC crediting framework should be developed,13 PG&E and CalCCA appear to largely agree on the issues in this case to date. CalCCA respectfully requests the Commission follow the recommendations set forth in both its Opening Brief and this Reply Brief. Further, CalCCA continues to review, and has issued discovery regarding, PG&E’s October Update and 12 A.22-05-029, Opening Brief of the Direct Access Customer Coalition, p. 2 (October 14, 2022) (“DACC Opening Brief”).
13 CalCCA Opening Brief at 20-23 (Commission precedent and common sense dictate it should be developed in the PCIA proceeding; nothing prevents the Commission for making that determination as part of this case).
4 will address any outstanding issues that may arise from that on-going analysis in its November 1, 2022 comments.

I. PG&E MUST IMPLEMENT PCIA RATE CREDITS FOR BUNDLED AND UNBUNDLED CUSTOMERS ON A FORECAST BASIS.

A. D.18-10-019 Rendered a PCIA Rate Floor Obsolete.

Contrary to PG&E’s assertions, the Commission’s indifference framework does not conflict with the concept of PCIA rate credits,14 only apply to “above-market” portfolio costs,15 or create a restriction on PCIA rates tied to what PG&E can demonstrate in its recorded balances. 16 PG&E admitted via discovery that D.18-10-019 and D.19-10-001 rendered obsolete the rate floor currently in its Electric Schedule CCA-CRS.17 Commission precedent eliminated all limits on PCIA rate changes, including the rate floor and the rate cap. 18 Decision 18-10-019 specifically
states that “the PCIA rate should be able to go negative and should credit departing customers when IOU portfolio value exceeds costs.”19 The Commission designed the indifference framework to incorporate rate credits, when the value of a utility’s portfolio is forecasted to exceed its costs, without restriction.
20 The context of that decision makes clear that neither Conclusion of Law 21 nor Finding of Fact 20 creates the restrictions PG&E tries to read into those provisions. 21 The juxtaposition of
14 A.20-05-029, Opening Brief of Pacific Gas and Electric Company (U 39 E), pp. 3, 13, 32-34 (August 14, 2022) (“PG&E Opening Brief”).
15 PG&E Opening Brief at 33 (citing to D.18-10-019 at COLs 10-12). 16 PG&E Opening Brief at 33.
17 A.20-05-029, California Community Choice Association’s Opening Brief, p. 12 (August 14, 2022) (“CalCCA Opening Brief”).
18 CalCCA Opening Brief at 12-13.
19 D.18-10-019 at 88.
20 Id. at 88, COL 21 and FOF 20; D.21-05-030 at Ordering Paragraph 1. 21 CalCCA Opening Brief at 14-15.
5 the complexity of PG&E’s proposal in this case, with the lack of discussion surrounding a proposal of its kind in the body of D.18-10-019, makes this clear. The rate floor PG&E suggests exists is quite nuanced. It would apply to only one component of the PCIA revenue requirement (a negative forecasted cumulative indifference amount), but not the other (the year-end true-up balance). 22 As
proposed in PG&E’s October Update and opening brief, it would require the creation of an entirely new balancing account outside of the PABA.23 As DACC’s Opening Brief notes, 24 it would be odd
for the Commission to create such a nuanced rate floor in a Conclusion of Law and a Finding of Fact with no discussion of establishing that rate floor in the body of the decision. The Commission never intended there to be any rate floor; it intended for there to be rate credits when customers are owed them. 25
B. Timely Recovery of Costs Does Not Permit PG&E to Overcharge Customers.

PG&E’s rationale that timely recovery of costs justifies overcharging customers and creating rate inconsistencies is incorrect. PG&E cites Section 454.5(d)(3)’s requirement that the Commission “[e]nsure timely recovery of prospective procurement costs incurred pursuant to an approved procurement plan,” concluding PCIA rate credits would “fundamentally conflict” with the timely recovery of procurement costs.26 There is no “fundamental conflict” between rate credits and PG&E’s timely recovery of costs because ratepayers’ only obligation is to pay rates based on forecasted revenue requirements. The timely recovery of costs does not mean PG&E can set rates to earn more than what is owed. If anything, PG&E’s proposal to not apply PCIA rate 22 Id. at 12-13.
23 Exh. PGE-4 at 24:17-25:4; PG&E Opening Brief at 36.
24 DACC Opening Brief at 2.
25 D.18-10-019 at 88, COL 21 and FOF 20; D.21-05-030 at Ordering Paragraph 1. 26 PG&E Opening Brief at 34-35.
6 credits runs directly counter to the very mechanism—rates based on forecasted revenue requirements—that ensures timely recovery of costs. The only amounts ratepayers owe to PG&E is a PCIA revenue requirement based on a forecasted indifference amount. PG&E’s brief itself exhibits as much, citing to D.11-10-012 to discuss how PG&E sets it rates based on forecasted procurement costs:27
The utility submits a forecast of its procurement expenses for the following year to the Commission for review and approval. The utility’s forecast is based on its best estimate of such factors as its projected sales and load, natural gas and power prices, etc., during the forecast year. The adopted forecast value is used to establish procurement related rates, but it does not determine which procurement-related costs are eligible for cost recovery.

PG&E does not get to decide it will use an “adopted forecast value” to set rates in one instance, but not in another, because the result may look less risky on its balance sheet.

PG&E’s Opening Brief raises concerns about the uncertain nature of forecasts, i.e., whether net market revenues will actually materialize,28 recent year-end balances arising from high energy prices in California,
29 and the high percentage of departed load in its service territory.30 These characteristics, the utility alleges, make reliance on the Commission’s true-up mechanism risky for the company’s shareholders. 31
All of this hand-waving, however, amounts to a concern that the true-up will not work for undercollections tied to rate credits the way it works for overcollections or other types of 27 Id. at 5-6 (emphasis added).
28 Id. at 35.
29 Id.
30 Id. at 36.
31 Id. at 35-36.
7 undercollections. Not only does PG&E provide no evidence in support of that assertion (only conjecture within a legal brief),32 it also ignores the simple mechanics of the true-up, which are the same for both positive and negative PCIA rates. Nothing about the PCIA/PABA framework changes if the PCIA is above-market or below-market. Projected costs are offset by projected wholesale revenue, and the net is recovered from customers. 33 With a positive PCIA rate that is set too low, the utility under-collects and needs to recover those costs the following year.34 The same is true for a negative PCIA rate, i.e., a PCIA rate credit. A credit that is too high will cause an undercollection that PG&E would need to recover in the following year.35 In both cases, moneys collected in PABA over the course of the year will fall short of the revenue requirement, the resulting under-collected year-end balance will be recorded to PABA, and PCIA rates will increase the following year (all other things equal).
36 This mechanism has worked since being
implemented after D.18-10-019.

PG&E incorrectly argues “D.21-05-030 removed the cap-and-trigger mechanism applicable to departing load customer rates, removing PG&E’s recourse to adjust departing load customer rates during within [sic] 2023 … .”37 While PG&E is correct that there is no “PCIA trigger” based on under- or over-collected PABA balances, that fact has nothing to do with D.21- 05-030. Rather, PG&E is discussing the Portfolio Undercollection Balancing Account (PUBA) 32 Commission ratemaking proceedings must be based on substantial evidence. CalCCA Opening Brief at 5-6.
33 See Exh. CalCCA-01 at 7:8-14.
34 See id.
35 See id.
36 Moreover, PG&E’s argument that wholesale revenue may not materialize could also be made when the PCIA is positive. Yet, the commission still nets projected wholesale revenue against costs before determining the amount due from customers.
37 PG&E Opening Brief at 36.
8 mechanism, which was tied to balances resulting from the rate cap, i.e., it was tied to balances in the PUBA and not the PABA. The PUBA trigger would not have addressed PG&E’s concerns in the unlikely hypothetical the utility is discussing.

PG&E’s argument does identify a real problem if its proposal is adopted. PG&E is correct that the Commission has only approved an ERRA Trigger and not a PABA trigger, but, in this case, that hurts customers more than the utility. Customers in vintages with negative indifference amounts have no trigger to help them if the balance owed to them builds and builds, i.e., there is no “PCIA Trigger” to give them relief for their overpayments to PG&E. That means an inaccurately forecasted indifference amount carries just as much risk for customers as for PG&E, except customers do not have access to debt and equity markets like PG&E. Their only recourse for being overcharged is to reduce their purchases of electricity. The Commission should avoid this consumer protection issue by rejecting PG&E’s proposal.

II. CONCLUSION
For the foregoing reasons, and those stated in CalCCA’s Opening Brief, CalCCA respectfully requests the Commission:
• Reject PG&E’s position and adopt PCIA rate credits for vintages where the forecasted, cumulative indifference amount is negative.
• Enact the procedural recommendation in D.20-02-047 to create a more permanent crediting framework for banked renewable energy credits in the Power Charge Indifference Adjustment rulemaking, R.17-06-026.
• Adopt CalCCA’s uncontested recommendations to adjust PG&E’s revenue requirement to address (1) the sale of PG&E’s San Francisco headquarters, (2) the correct on-peak and off-peak load weights, and (3) Witness Shuey’s accounting methodology to reflect PG&E’s Modified Cost Allocation Mechanism procurement.
• Adopt CalCCA’s uncontested recommendation to transfer the final year of Energy Resource Recovery Account-PCIA Financing Subaccount amortization to the vintage 2020 consistent with Commission direction in D.22-02-002.
9 CalCCA reserves the right to modify these recommendations based on updated information presented in PG&E’s October Update, and to address other issues raised therein, via comments on the October Update, or any further process the Commission may adopt.

Respectfully submitted,
Tim Lindl
Nikhil Vijaykar

KEYES & FOX LLP
580 California Street, 12th Floor
San Francisco, CA 94104
Telephone: (510) 314-8385
Email: [email protected]
[email protected]
Counsel to CalCCA
October 21, 2022
~

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Implementation and Administration, and
Consider Further Development, of California
Renewables Portfolio Standard Program.

R.18-07-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S

REPLY COMMENTS ON THE PROPOSED DECISION APPROVING VOLUNTARY

ALLOCATIONS AND MODIFYING MARKET OFFER PROCESS FOR THE SALE OF

EXCESS RENEWABLE RESOURCES TO LOWER POWER CHARGE
INDIFFERENCE ADJUSTMENT COSTS PURSUANT TO DECISION 21-05-030 Evelyn Kahl
General Counsel and Director of Policy
Leanne Bober
Senior Counsel

CALIFORNIA COMMUNITY CHOICE

ASSOCIATION
One Concord Center
2300 Clayton Road, Suite 1150
Concord, CA 94520
Telephone: (415) 254-5454
E-mail: [email protected]
Ann Springgate

KEYES & FOX LLP
580 California Street, 12th Floor
San Francisco, CA 94104
Telephone: (415) 987-8367
E-mail: [email protected]
Counsel to
California Community Choice Association
October 24, 2022
FILED
10/24/22
04:59 PM
R1807003
ii

SUMMARY OF RECOMMENDATIONS
• Pacific Gas and Electric Company’s (PG&E’s) and Southern California Edison Company’s (SCE’s) arguments against removing their “waived claims” language regarding remedies for violations related to Market Offer solicitations should be rejected as PG&E and SCE ignore the unique nature of the Market Offers and the importance of ensuring investor-owned utility (IOU) portfolio optimization is administered effectively and equitably;
• San Diego Gas & Electric Company’s (SDG&E’s) request for a revision of the Code of Conduct requirements to allow IOU employees to transfer between the Market Offer bid and evaluation teams after bids are submitted should be rejected due to the potential for the IOUs to gain a competitive advantage; and
• The Proposed Decision should be clarified as requested by SCE to specify that all Power Charge Indifference Adjustment (PCIA)-eligible renewables portfolio standard (RPS) resources left over after the Voluntary Allocation are available for contracting in the Market Offer as required by Decision (D.) 21-05-030.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
Implementation and Administration, and
Consider Further Development, of California
Renewables Portfolio Standard Program.

R.18-07-003
CALIFORNIA COMMUNITY CHOICE ASSOCIATION’S

REPLY COMMENTS ON THE PROPOSED DECISION APPROVING VOLUNTARY

ALLOCATIONS AND MODIFYING MARKET OFFER PROCESS FOR THE SALE OF

EXCESS RENEWABLE RESOURCES TO LOWER POWER CHARGE
INDIFFERENCE ADJUSTMENT COSTS PURSUANT TO DECISION 21-05-030 The California Community Choice Association (CalCCA)1
submits these reply
comments pursuant to Rule 14.3 of the California Public Utilities Commission (Commission) Rules of Practice and Procedure on the proposed Decision Approving Voluntary Allocations and Modifying Market Offer Process for the Sale of Excess Renewable Resources to Lower Power Charge Indifference Adjustment Costs Pursuant to Decision 21-05-030 (Proposed Decision or PD), dated September 29, 2022.
1 California Community Choice Association represents the interests of 24 community choice electricity providers in California: Apple Valley Choice Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Desert Community Energy, East Bay Community Energy, Energy For Palmdale’s Independent Choice, Lancaster Choice Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy.
2 I. PG&E AND SCE’S ARGUMENTS AGAINST REMOVING THEIR “WAIVED CLAIMS” LANGUAGE IGNORES THE UNIQUE NATURE OF THE MARKET

OFFER AND THE IMPORTANCE OF ENSURING IOU PORTFOLIO

OPTIMIZATION IS EQUITABLE
As CalCCA has emphasized, the Market Offer process, including the solicitation protocols, investor-owned utility (IOU) Codes of Conduct, and Sales Strategies developed for use in the Market Offers, is novel. The Voluntary Allocation Market Offer (VAMO) was created to accomplish Commission-ordered IOU portfolio optimization for the benefit of ratepayers throughout the state for years to come. Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (SCE) comment that the “waived claims” language put forward in their Market Offer pro forma contracts is standard in their own renewables portfolio standard (RPS) solicitation materials, and similar language has been used by various community choice aggregators (CCAs).
2 PG&E and SCE also claim that the Market Offer is similar to many previous RPS solicitations, and the remedies should match the remedies from those previous offers and be allowed in their Market Offer pro forma contracts. 3 While the Commission intended the documents used in the Market Offer to be “based upon” standard forms where possible,4 the Market Offers themselves are not “standard” transactions. The PD itself recognizes “certain aspects of the Market Offer process vary from the RPS rules and requirements due to the structure set up in Decision (D.) 21-05-03.”5 2 PG&E Opening Comments at 2-4; SCE Opening Comments at 8-10. 3 See PG&E Opening Comments at 2 (PG&E’s waived claims language “has been in place and successfully utilized as part of its RPS solicitations approved as part of its Commission-overseen RPS plans”); see also SCE Opening Comments at 8 (“[t]he Market Offer process is not appreciably different from any other solicitation that SCE runs, and it is very similar to SCE’s past REC sales solicitations”). 4 D.21-05-030, Phase 2 Decision on Power Charge Indifference Adjustment Cap and Portfolio Optimization, Rulemaking (R.) 17-06-026 (May 20, 2021) (Phase 2 Decision), Conclusion of Law (COL) 8(b) at 59 ([t]he Market Offer process should be based upon existing processes, rules, oversight requirements, and reporting requirements for IOU REC solicitations previously approved in the Commission’s proceeding”).
5 PD, COL 3 at 35.
3 The Market Offer transactions are not “simple” RPS solicitations, which is evident by the IOUs’ requests for significant additional time to submit compliant pro forma contracts. The IOUs themselves may participate in the Market Offers, either in their own offers, or in those of the other IOUs.6
Violations in bidding or in evaluating bids will seriously impact the market price of RPS used to calculate the Power Charge Indifference Adjustment (PCIA) for all ratepayers.

Unlike a “standard” IOU RPS solicitation, the injured party in the case of a mishandled Market Offer solicitation is not just the bidder who loses the contract.

CalCCA reiterates that remedies for IOU violations of the approved Market Offer process should be significant enough to deter the prohibited behavior. An order from the Commission that the solicitation be redone is inadequate. PG&E and SCE’s “waived claims” language is therefore inappropriate for the Market Offer pro forma contracts.

II. SDG&E’S REQUEST TO ALLOW IOU EMPLOYEES TO TRANSFER

BETWEEN MARKET OFFER BID AND EVALUATION TEAMS AFTER BIDS

ARE SUBMITTED SHOULD BE REJECTED DUE TO THE POTENTIAL IOU

COMPETITIVE ADVANTAGE
San Diego Gas & Electric (SDG&E) objects to the PD’s prohibition of members of an IOU’s bid team moving to an evaluation team during the Market Offer evaluation process (i.e., after bids are submitted) when an IOU participates in its own Market Offer solicitation.7 In fact, consistent with Codes of Conduct approved in other situations in which IOUs participate in their own solicitations,8 the PD requires firewalls between bid and solicitation teams to remain in place for one year after the Commission approves the last Market Offer contract.9 SDG&E states that “once bids 6 Phase 2 Decision, COL 8(c) at 60 (requiring “rules for IOU participation in solicitations they administer” in the Market Offer).
7 SDG&E Opening Comments at 4 (referring to the PD at 24, and Ordering Paragraph (O¶) 8(a) at 38-39).
8 See R.18-07-003, California Community Choice Association’s Comments on Market Offer Process (June 6, 2022), at 7, n.12. 9
PD at 24, and O¶ 8(a) at 38-39.
4 are submitted there is no conceivable market-harm or IOU-specific benefit by allowing that “bid-formulating” employee to subsequently transfer to a role involving “bid evaluation” tasks.10 After bids are submitted, additional negotiations may occur between the evaluation team and bidders. An employee with knowledge of IOU information and strategy concerning the IOU’s bid should not be part of that continuing evaluation and negotiation process. Any such participation could result in an unfair advantage for the IOU and should be prohibited.

Accordingly, the Commission should reject SDG&E’s request.

III. THE PD SHOULD BE CLARIFIED AS REQUESTED BY SCE TO SPECIFY

THAT ALL PCIA-ELIGIBLE RPS RESOURCES LEFT OVER AFTER THE

VOLUNTARY ALLOCATION ARE AVAILABLE FOR MARKET OFFER

CONTRACTING
As stated in CalCCA’s Opening Comments on the PD, the Commission should remove the requirement that the IOUs offer long-term contracts in this first Market Offer if such an offering will cause delay in the solicitation beyond the first quarter of 2023.11 Regardless of the Commission’s decision on this issue, however, the PD should be clarified as requested by SCE to ensure that all PCIA-eligible RPS energy remaining after the Voluntary Allocation is offered in the Market Offer as required by the Phase 2 Decision.12 Therefore, Ordering Paragraph (O¶) 3 of the PD should be revised to remove the phrase “short-term,” to read:

3. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company are approved to offer 100 percent of their remaining Power Charge Indifference Adjustment eligible short-term contracts in the Market Offer.13 10 SDG&E Opening Comments at 4.
11 CalCCA Opening Comments at 6-8.
12 Phase 2 Decision, O¶ 3(a) at 64.
13 PD, O¶ 3 at 38. In addition, while CalCCA recommends that the Commission remove the requirement that the IOUs offer long-term contracts, if it does adopt this requirement the following changes to O¶ 4 should also be made:
5 IV. CONCLUSION
CalCCA appreciates the opportunity to submit these reply comments and requests adoption of the recommendations proposed herein.

Respectfully submitted,
/s/ Ann Springgate
Ann Springgate

KEYES & FOX LLP
580 California Street, 12th Floor
San Francisco, CA 94104
Telephone: (415) 987-8367
E-mail: [email protected]
Counsel to
California Community Choice Association
October 24, 2022

4. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall offer 35 percent of the eligible remaining Power Charge Indifference Adjustment eligible resources through long term-contracts in the Market Offer.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Develop a
Successor to Existing Net Energy Metering
Tariffs Pursuant to Public Utilities Code
Section 2827.1, and to Address Other Issues
Related to Net Energy Metering.

Rulemaking 14-07-002
And Related Matters Application 16-07-015

QUARTERLY DISADVANTAGED COMMUNITIES GREEN TARIFF AND

COMMUNITY SOLAR GREEN TARIFF PROGRAMS REPORT
FOR JULY 1, 2022 TO SEPTEMBER 30, 2022 OF MARIN CLEAN ENERGY Amulya Yerrapotu
Policy Associate
Marin Clean Energy
1125 Tamalpais Ave.

San Rafael, CA 94901
925.222.5153
[email protected]
October 27, 2022
1 BEFORE THE PUBLIC UTILITIES COMMISSION

Rulemaking 14-07-002
And Related Matters Application 16-07-015

QUARTERLY DISADVANTAGED COMMUNITIES GREEN TARIFF AND

COMMUNITY SOLAR GREEN TARIFF PROGRAMS REPORT
FOR JULY 1, 2022 TO SEPTEMBER 30, 2022 OF MARIN CLEAN ENERGY Marin Clean Energy (“MCE”) submits this Disadvantaged Communities Green Tariff (“DAC-GT”) and Community Solar Green Tariff (“CSGT”) quarterly report in accordance with Resolution E-4999, issued June 3, 2019. Ordering Paragraph (“OP”) 1(f) of Resolution E-4999 states:
“Once an IOU has completed its first RFO or initiated customer enrollment, whichever occurs first, within 30 Calendar Days after the end of each calendar quarter, PG&E, SCE, and SDG&E shall file a report in R.14-07-002, or a successor proceeding, and serve the same report on that service list, for the previous quarter and cumulatively, with the following minimum information for the DAC-GT and CSGT programs: capacity procured, capacity online, and customers subscribed. The quarterly reports should also identify the DACs in which DAC-GT or CSGT project is located and list the number of customers participating in each program in each DAC within a utility’s service territory.

Finally, the quarterly reports must include the number of customers who have successfully enrolled in CARE and FERA in the process of signing up for the DAC-GT or CSGT programs.”1
1 Resolution E-4999, Pursuant to Decision 18-06-027, Approving with Modification, Tariffs to Implement the Disadvantaged Communities Green Tariff and Community Solar Green Tariff Programs, p. 63, OP 1(f).
2 As program administrators, CCAs are subject to the same reporting requirements as investor-owned utilities (“IOUs”) and MCE hereby submits a quarterly report for DAC-GT and CSGT covering the period of July 1, 2022 to September 30, 2022, attached hereto as Attachment A.

Respectfully submitted,
/s/ Amulya Yerrapotu
Amulya Yerrapotu
Policy Associate
Marin Clean Energy
1125 Tamalpais Ave.

San Rafael, CA 94901
925.222.5153
[email protected]
October 27, 2022

ATTACHMENT A
1 QUARTERLY DISADVANTAGED COMMUNITIES GREEN TARIFF

AND COMMUNITY SOLAR GREEN TARIFF PROGRAMS REPORT
FOR JULY 1, 2022 TO SEPTEMBER 30, 2022 OF MARIN CLEAN ENERGY Pursuant to Decision 18-06-027 (“Decision”)2 and in accordance with Resolution E-4999,3 Marin Clean Energy (“MCE”) files this quarterly report on the Disadvantaged Communities Green Tariff (“DAC-GT”) and Community Solar Green Tariff (“CSGT”) programs for the period July 1, 2022 to September 30, 2022. MCE reports on the following program metrics as required by Resolution E-4999:

1. Capacity procured and online;

2. Participating customers, including breakdown by Disadvantaged Community (“DAC”);

3. California Alternate Rates for Energy (“CARE”) and Family Electric Rate Assistance (“FERA”) enrollment.4

1. Capacity Procured and Online
The DAC-GT program (branded as MCE’s “Green Access” program) has a capacity cap of 4.64 MW. The CS-GT program (branded as MCE’s “Community Solar Connection” program) has a capacity cap of 1.28 MW.5
On August 27, 2021, MCE launched the first DAC-GT and CSGT solicitation, with bids due on November 19, 2021. MCE received bids for the DAC-GT program and signed PPAs to fill the total program capacity (4.64 MW). The resources are anticipated to be online by December 2023.

MCE received no bids for the CSGT program. MCE issued another RFO for CSGT in August, 2022; all offers are due by November 18, 2022. As such, as of the date of this report MCE does not have any new capacity procured or online under either the DAC-GT or the CSGT program.

Enrolled customers under the DAC-GT program are currently being served by “interim resources” that meet the eligibility requirements of the programs in accordance with Resolution E-4999.6 MCE is serving DAC-GT customers with solar generation from the Goose Lake project, located at 15004 Corcoran Rd., Lost Hills, CA 93249 in DAC census tract 6031001300. 2 Decision 18-06-027, Alternate Decision Adopting Alternatives to Promote Solar Distributed Generation in Disadvantaged Communities, issued June 22, 2018, p. 55. 3 Resolution E-4999, p. 40 and p. 63, OP 1(f).
4 Resolution E-4999, OP 1(f).
5 Resolution E-4999 allocated MCE 4.31 MW for DAC-GT and 1.11 MW for CSGT (at p. 14).

Subsequently San Jose Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Central Coast Community Energy declined to offer DAC-GT and CSGT programs for 2021, and their allocated capacity was redistributed equally among participating CCAs in accordance with Resolution E-5124 6 Resolution E-4999, p. 24 and p. 63 OP 1(i), permits PAs to serve DAC-GT customers through existing eligible resources that meet all other DAC-GT program rules on an interim basis, until new DAC-GT projects are interconnected.
2 2. Participating Customers
The DAC-GT and CSGT programs provide a 20% bill discount to eligible customers located in DACs. DACs are defined under D.18-06-027 as communities that are identified in the CalEnviroScreen (“CES”) tool as among the top 25 percent of census tracts statewide, plus the census tracts in the highest five percent of CES’ Pollution Burden that do not have an overall CES score because of unreliable socioeconomic or health data.7 The DAC-GT program is available to residential customers who live in DACs, receive generation service from MCE, and meet the income eligibility requirements for the CARE program and/or the FERA program.8 In MCE AL 42-E-A, MCE opted to auto-enroll eligible customers that live in one of the top 10% of DAC census tracts statewide in MCE’s service area if they meet certain criteria.9
The CSGT program is available to residential customers who live in DACs (as defined by D.18- 06-027) and receive generation service from MCE. Non-residential customers are not eligible to participate, except for the project sponsor. A solar generation project supporting the program must be located within five miles of the participating customers’ census tract. At least fifty percent of a project’s capacity must be reserved for low-income customers, defined as those meeting the income qualifications for either the CARE or FERA programs.10 Table 1 sets forth, for each program, the number of customers participating in each program to date. As noted above, MCE is still in the process of procuring solar generation for the CSGT program and as such has no participating customers to date. As noted above, participating customers under the DAC-GT program are being served by interim resources.

Table 1: Participating Customers in DAC-GT and CSGT Programs

DAC-GT CSGT
Customers Subscribed as of 9/30/2022 3,269 0
Table 2 indicates the number of customers participating in the DAC-GT program grouped by DAC census tract number.
7 D.18-06-027, p. 16 and p. 96, Conclusion of Law 3.
8 D.18-06-027, p. 51.
9 MCE AL 42-E-A, p. 3.
10 D.18-06-027, Section 6.5.3.
3 Table 2: Participating Customers in DAC-GT by DAC Census Tract Census
Tract
County City (closest by proximity) Count
6013312000 Contra Costa County 251 Pittsburg
6013365002 Contra Costa County 541 Richmond
6013376000 Contra Costa County 311 Richmond
6013377000 Contra Costa County 853 Richmond
6013379000 Contra Costa County 682 Richmond
6013380000 Contra Costa County 2 Richmond
6013382000 Contra Costa County 203 Richmond
6095250701 Solano County 168 Vallejo
6095250900 Solano County 258 Vallejo
Grand
Total 3,269

3. CARE and FERA Customer Enrollments
MCE auto-enrolled its customers in the DAC-GT program. To date, no CARE/ FERA enrollment occurred as a result of the DAC-GT or CS-GT enrollment for customers in MCE’s service area.

4. CSGT Project Details
As indicated above, MCE received no bids in its 2021 solicitation for CSGT projects, and as a result has enrolled no customers in CSGT. As such, MCE has no project details to report at this time.

BEFORE THE PUBLIC UTILITIES COMMISSION

Rulemaking 14-07-002
And Related Matters Application 16-07-015

QUARTERLY DISADVANTAGED COMMUNITIES GREEN TARIFF AND

COMMUNITY SOLAR GREEN TARIFF PROGRAMS REPORT
FOR JULY 1, 2022 TO SEPTEMBER 30, 2022 OF MARIN CLEAN ENERGY Amulya Yerrapotu
Policy Associate
Marin Clean Energy
1125 Tamalpais Ave.

San Rafael, CA 94901
925.222.5153
[email protected]
October 27, 2022
1 BEFORE THE PUBLIC UTILITIES COMMISSION

Rulemaking 14-07-002
And Related Matters Application 16-07-015

QUARTERLY DISADVANTAGED COMMUNITIES GREEN TARIFF AND

Respectfully submitted,
/s/ Amulya Yerrapotu
Amulya Yerrapotu
Policy Associate
Marin Clean Energy
1125 Tamalpais Ave.

San Rafael, CA 94901
925.222.5153
[email protected]
October 27, 2022

ATTACHMENT A
1 QUARTERLY DISADVANTAGED COMMUNITIES GREEN TARIFF

1. Capacity procured and online;

2. Participating customers, including breakdown by Disadvantaged Community (“DAC”);

3. California Alternate Rates for Energy (“CARE”) and Family Electric Rate Assistance (“FERA”) enrollment.4

Table 1: Participating Customers in DAC-GT and CSGT Programs

Standard LSE Plan

MARIN CLEAN ENERGY
2022 INTEGRATED RESOURCE PLAN
NOVEMBER 1, 2022
1 Table of Contents
I. Executive Summary ................................................................................................................ 4 a. Introduction .................................................................................................................. 4 Description of MCE................................................................................................................................................ 4 MCE’s Mission ....................................................................................................................................................... 5 Introduction to MCE’s Compliance IRP.................................................................................................................. 6 MCE’s Preferred Conforming Portfolio.................................................................................................................. 7 Request for Certification ....................................................................................................................................... 8 b. Summary of Findings .................................................................................................... 9 II. Study Design ........................................................................................................................11 a. Objectives ...................................................................................................................11 b. Methodology ..............................................................................................................12 i. Modeling Tool(s) .................................................................................................................... 12 ii. Modeling Approach................................................................................................................ 13 Load Forecast ......................................................................................................................................................13 Table 1: MCE’s 2023-2035 Load Forecast............................................................................................................13 Load Shape ..........................................................................................................................................................13 Compiling Existing Resources..............................................................................................................................14 Selecting New Resources.....................................................................................................................................14 Confirming Reliability ..........................................................................................................................................14 Calculating GHG Emissions..................................................................................................................................15 III. Study Results ........................................................................................................................15 a. Conforming and Alternative Portfolios .......................................................................15 Table 2: MCE’s 2035 PCP Resources....................................................................................................................15 MCE’s PCP Is Consistent with the 2021 PSP ........................................................................................................17 Table 3: MCE’s PCP New Resource Procurement by Type Compared to 2021 PSP.............................................18 b. Preferred Conforming Portfolio ..................................................................................19 Meeting GHG Reduction Goals............................................................................................................................20 Procuring Eligible Renewable Energy ..................................................................................................................21 Minimizing Bill Impact.........................................................................................................................................21 Ensuring System and Local Reliability..................................................................................................................22 Strengthening the Bulk Transmission and Distribution Systems.........................................................................23 Enhancing Demand-Side Energy Management...................................................................................................23 Minimizing Localized Air Pollutants with Emphasis on Disadvantaged Communities.........................................24 c. GHG Emissions Results ...............................................................................................25 Table 4: MCE’s PCP GHG Emissions.....................................................................................................................25 d. Local Air Pollutant Minimization and Disadvantaged Communities ...........................25 i. Local Air Pollutants................................................................................................................. 25 Table 5: MCE’s PCP Local Pollutant Emissions (30 MMT Scenario).....................................................................25 Table 6: MCE’s PCP Local Pollutant Emissions (25 MMT Scenario).....................................................................26 ii. Focus on Disadvantaged Communities.................................................................................. 26 I
2 Table 7: DACs Served by MCE..............................................................................................................................26 Green Access and Community Solar Connection Programs................................................................................29 Sustainable Workforce and Diversity Policy........................................................................................................30 Ad Hoc Workforce Development ........................................................................................................................31 Creating Energy Efficiency Jobs...........................................................................................................................33 Equity in Power Purchasing ................................................................................................................................. 34 Strategic Recruiting and Hiring Practices ............................................................................................................34 Community Power Coalition................................................................................................................................34 Building Community Resiliency ...........................................................................................................................35 COVID-19 Customer Support...............................................................................................................................36 e. Cost and Rate Analysis ................................................................................................36 f. System Reliability Analysis. .........................................................................................38 g. High Electrification Planning .......................................................................................40 Table 8: MCE’s 2024-2035 Load Forecast - High Electrification Scenario............................................................41 Table 9: MCE’s 2024-2035 Peak Demand Forecast - High Electrification Scenario.............................................41 Table 10: MCE’s Planned Out-of-State and Off-Shore Wind Resources..............................................................42 h. Existing Resource Planning .........................................................................................42 i. Hydro Generation Risk Management .........................................................................43 j. Long-Duration Storage Planning .................................................................................44 k. Clean Firm Power Planning .........................................................................................45 l. Out-of-State Wind Planning ........................................................................................45 m. Offshore Wind Planning ..............................................................................................46 n. Transmission Planning ................................................................................................46 i. New Projects.......................................................................................................................... 46 ii. Projects Under Development................................................................................................. 46 iii. Projects Under Review........................................................................................................... 48 iv. Planned New (Generic) Projects ............................................................................................ 49 IV. Action Plan ...........................................................................................................................50 a. Proposed Procurement Activities and Potential Barriers ...........................................50 Joint Solicitations.................................................................................................................................................50 Optimizing Existing Procurement........................................................................................................................51 Annual Energy Solicitations................................................................................................................................. 51 i. Resources to meet D.19-11-016 procurement requirements................................................ 54 D.19-11-016 Procurement Progress Report ........................................................................................................54 Sutter Energy Center...........................................................................................................................................55 Strauss Wind, LCC................................................................................................................................................55 MCE Solar One.....................................................................................................................................................56 Waste Management Redwood Landfill (“Redwood Landfill Project”) ................................................................56 i. Resources to meet D.21-06-035 procurement requirements, including: .............................. 57 MTR Procurement Progress Report.....................................................................................................................57 i. All other procurement requirements..................................................................................... 59 I
3 Open Season RFO................................................................................................................................................59 ii. Offshore wind ........................................................................................................................ 60 iii. Out-of-state wind................................................................................................................... 60 iv. Other renewable energy not described above ...................................................................... 60 v. Other energy storage not described above ........................................................................... 60 vi. Other demand response not described above....................................................................... 61 vii. Other energy efficiency not described above ........................................................................ 61 viii. Other distributed generation not described above ............................................................... 62 Net Energy Metering and Rooftop Solar Rebates ...............................................................................................62 ix. Transportation electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR) ........................................................................................ 63 x. Building electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR)............................................................................................ 64 Multifamily Energy Saving Program ....................................................................................................................64 LIFT Pilot Program ...............................................................................................................................................65 Home Energy Savings (“HES”) Program...............................................................................................................66 Heat Pump Water Heater (“HPWH”) Contractor Incentive Program..................................................................67 xi. Other...................................................................................................................................... 67 b. Disadvantaged Communities ......................................................................................67 Green Access and Community Solar Connection Programs................................................................................67 Sustainable Workforce and Diversity Policy........................................................................................................68 c. Commission Direction of Actions ................................................................................68 V. Lessons Learned ...................................................................................................................69 Glossary of Terms.........................................................................................................................70 I
4 I. Executive Summary
a. Introduction
Description of MCE
Marin Clean Energy (“MCE”) is California’s first Community Choice Aggregation (“CCA”) Program, a not-for-profit Joint Powers Authority (“JPA”) that began service in 2010. MCE’s mission is to confront the climate crisis by eliminating fossil fuel greenhouse gas (“GHG”) emissions, producing renewable energy, and creating equitable community benefits. MCE’s vision is to lead California to an equitable, clean, affordable, and reliable energy economy by serving as a model for community-based renewable energy, energy efficiency, and cutting-edge clean-tech products and programs.

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

MCE provides service to approximately 87% of eligible customers within its service area, which is depicted in Figure 1, below. MCE is also the default generation provider for any new or relocated customers therein.2
1 MCE serves communities across Contra Costa, Marin, Napa, and Solano counties. Those communities currently receiving service include: Unincorporated Contra Costa, Marin, Napa, and Solano counties and the Cities and Towns of Concord, Danville, El Cerrito, Lafayette, Martinez, Moraga, Oakley, Pinole, Pittsburg, Pleasant Hill, Richmond, San Pablo, San Ramon, Walnut Creek, Belvedere, Corte Madera, Fairfax, Larkspur, Mill Valley, Novato, Ross, San Anselmo, San Rafael, Sausalito, Tiburon, American Canyon, Calistoga, Napa, St. Helena, Yountville, Benicia, Vallejo, and Fairfield.
2 MCE expanded service to the city of Fairfield in April 2022. This expansion is reflected in MCE’s Commission-assigned load forecast. Expansion to additional communities may occur during the planning period.
5 Figure 1: Service Area Map
As a JPA and local government agency, MCE is governed by a 31-member Board of Directors (“Board” or “Governing Board”) composed of elected representatives from MCE’s member communities. MCE’s Board sets policy for the agency and oversees MCE’s operations, including MCE’s procurement planning. Through these representatives, MCE is controlled by and accountable to the communities MCE serves.

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

Marin '
County
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Napa
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Solano c.,,,o, County
Contra Costa
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6 Member community values and needs are reflected in a number of procurement principles, goals, targets, and directives reviewed and adopted by MCE’s Board via MCE’s annual Operational Integrated Resource Plan (“Operational IRP”).3 Since 2014, MCE has prepared an annual Operational IRP as an internal planning and policy document to address MCE’s GHG reduction targets and various other agency matters related to resource planning and procurement, including complementary energy programs administered and funded by MCE.

The Operational IRP is well-aligned with the biennial Compliance IRP submitted to the California Public Utilities Commission (“Commission” or “CPUC”) for certification pursuant to Cal. Pub.

Util. Code Section 454.52(b)(3).4 These two IRPs are developed concurrently in even years and describe consistent long-term procurement planning strategies and goals.

Consistent with Sections 366.2(a)(5) and 454.52 (b)(3), MCE’s procurement is governed by MCE’s Board and must be consistent with the Board-adopted mandates in MCE’s Operational IRP.

Introduction to MCE’s Compliance IRP
In accordance with the requirements of Sections 454.51 and 454.52, Commission Decisions (“D.”) 22-02-004, D.21-06-035, D.19-11-016, D.18-02-018, and formal guidance provided by the Commission’s Energy Division,5 MCE is filing its Compliance IRP for certification review and use in the Commission’s statewide planning process. In addition to this narrative, MCE’s Compliance IRP includes the following documents:
● MCE’s 30 MMT Resource Data Template;
● MCE’s 25 MMT Resource Data Template;
● MCE’s 30 MMT Clean System Power Calculator; and
● MCE’s 25 MMT Clean System Power Calculator.
3 The current MCE 2022 Operational Integrated Resource Plan was approved by MCE’s Technical Committee in November 2021 and is available on MCE’s website: https://www.mcecleanenergy.org/energy-procurement/. MCE is developing its 2023 Operational Integrated Resource Plan concurrently with this Compliance IRP. The 2023 OIRP is scheduled to be reviewed and approved by MCE’s Technical Committee in November 2022. 4 All further citations to statute are to the California Public Utilities Code unless otherwise noted. 5 Over the course of the IRP planning cycle, Energy Division has issued a number of guidance documents to be used as LSEs develop their IRPs. These documents include LSE Filing Requirements RESOLVE Results (issued June 15, 2022); Filing Requirements Overview (updated July 15, 2022); Filing Requirements Questions and Answers (updated September 23, 2022); Clean System Power Calculator Documentation (updated July 15, 2022); Resource Data Template v3 User Guide (updated September 23, 2022); and Aggregated CAM Resources for LSEs Plan Development (issued September 29. 2022).
7 As provided for in D.22-02-004 and described in Commission Guidance documents, MCE is submitting a single conforming portfolio (“Preferred Conforming Portfolio”) as part of its Compliance IRP, which meets the following GHG emissions limits:

1. A portfolio that achieves emissions that are equal to or less than MCE’s proportional share of the 38 MMT by 2030 and 30 MMT by 2035 GHG targets (“30 MMT Conforming Portfolio); and

2. A portfolio that achieves emissions that are equal to or less than MCE’s proportional share of the 30 MMT by 2030 and 25 MMT by 2035 GHG targets (“25 MMT Conforming Portfolio”).

Projecting resource needs over the planning horizon covered by the IRP is an inexact exercise and is inevitably and appropriately subject to change in terms of both amounts procured and types of resources needed. MCE’s portfolio of resources generally includes (a) existing and operating resources that are under contract with MCE; (b) resources that MCE has contracted for, but that have not achieved commercial operation; and (c) future resources that MCE will need to procure to meet its agency targets and goals over both the mid- and long-term. The future resources identified in MCE’s Compliance IRP represent MCE’s best, good-faith projection of the resource mix it will procure over the IRP planning horizon based on currently available information. The resources identified in future iterations of MCE’s Compliance IRP may change due to new information and changed circumstances. As such, the ultimate resource mix MCE procures may differ from what is reflected in this Compliance IRP due to a number of variables including regulatory changes, availability of supply, price of supply, and/or other market or regulatory considerations. What MCE expects to remain constant, however, is its aggressive trajectory towards procuring a diverse resource mix that meets MCE’s reliability and customer needs and minimizes reliance on GHG-emitting resources for both energy and capacity.

MCE’s Preferred Conforming Portfolio
MCE’s Preferred Conforming Portfolio (“PCP”) is described in detail below and is represented in MCE’s Resource Data Template, version 3 (“RDT”) for both the 30 MMT Conforming Portfolio and the 25 MMT Conforming Portfolio, respectively. The PCP has been approved by MCE’s Chief Executive Officer and Governing Board as: (a) reflective of MCE’s actual planned procurement as of the filing of this Compliance IRP; (b) consistent with MCE’s statutory obligations; (c) consistent with the Commission’s IRP framework and guidelines, including the Preferred System Plan (“PSP”); (d) consistent with the Commission’s reliability requirements; and (c) consistent with MCE’s internal short-, mid-, and long-term procurement plans and internal procurement policies. MCE’s PCP comes in under its assigned portion of the 25 MMT 8 and 30MMT system emissions targets. MCE’s PCP was approved by MCE’s governing Board on October 20, 2022 and is being provided to the Commission for certification consistent with Section 454.52(b)(3).

Request for Certification
MCE respectfully requests that the Commission certify this Compliance IRP.

As both the Legislature and the Commission have recognized, the Legislature has granted CCAs broad authority to procure resources on their customers’ behalf, an authority limited only where “other generation procurement arrangements have been expressly authorized by statute.”6 The Commission has likewise recognized that the Legislature has granted CCAs autonomy in setting their own rates and managing interactions with their customers.7 As such, the Commission has three primary interests in the CCA IRP process:
● Ensuring that CCA IRPs provide the CCA procurement information that the Commission needs to develop its statewide plan;8
● Ensuring that CCAs’ current and planned procurement is consistent with the resource adequacy (“RA”) requirements established pursuant to Section 380;9 and ● Ensuring that each CCA contributes to grid reliability and GHG emissions reductions through the procurement of long-term renewable integration resources. 10 MCE has prepared its Compliance IRP with these interests in mind, and MCE thanks the Commission in advance for its recognition of CCA procurement autonomy and the benefits of a collaborative approach with CCAs in its certification review of MCE’s Compliance IRP. 6 Section 366.2(a)(5).
7 D.05-12-041 at 5 (“Nothing in the statute directs the CPUC to regulate the CCA’s program except to the extent that its programs may affect utility operations and the rates and services to other customers. For example, the statute does not require the CPUC to set CCA rates or regulate the quality of its services.”); D.19-04-040 at 18 (“[T]he Commission does not approve CCA or ESP rates.”). 8 D.19-04-040 at 17-18 (“The Commission’s portfolio aggregation and evaluation process, which relies of fulfillment of IRP filing requirements by LSEs, is the only process capable of assessing the overall needs of the CAISO grid and meeting the statewide GHG, reliability, and least-cost goals collectively. While LSEs may use their IRP process to meet local planning needs as well, the statewide planning function is the statutorily required process.
9 Section 454.52(b)(3)(C).
10 Section 454.51.
9 b. Summary of Findings
This narrative provides a detailed description of: (a) the development and content of MCE’s PCP; (b) the PCP’s compliance with applicable requirements; and (c) an Action Plan detailing MCE’s planned next steps to implement its plan.

MCE developed its Compliance IRP through the following steps:
● MCE compiled data for its existing energy-only contracts, bundled energy and capacity contracts, RA capacity contracts, and its share of capacity for allocated Cost Allocation Mechanism (“CAM”) and Demand Response resources;
● For each IRP planning year, MCE identified its short positions relative to MCE's planning targets in relation to its assigned load forecast; ● MCE populated the RDTs with all current contracts;
● MCE compiled information on projects for which it is currently negotiating power purchase agreements (“PPA”), including information regarding project status and timing;11
● MCE identified future contracts it expects for new geothermal, storage, and wind generation. MCE prioritized the selection of future resources that best fit MCE’s portfolio and that meet or exceed MCE’s proportional share of planned new procurement;
● MCE added generic future contracts with existing resources to help fill its remaining open positions;
● MCE used the Commission’s Clean System Power (“CSP”) calculator to check the GHG emissions associated with the resulting portfolio to ensure that these emissions are lower than MCE’s assigned share of the 30 MMT and 25 MMT benchmarks; ● MCE identified the resulting portfolio as its Preferred Conforming Portfolio or PCP; and ● MCE checked its PCP for reliability by comparing the total portfolio Net Qualifying Capacity (“NQC”) against MCE’s forecast RA requirements for the month of September in each year of the planning period.

MCE reached the following findings regarding its PCP:
● MCE’s PCP includes the procurement of the following new resources and nameplate capacities over the course of the planning horizon:
11 In the interest of providing the Commission as much current information as possible, MCE’s RDTs include information on projects under negotiation to the extent commercially reasonable and feasible. MCE asserts, though, the information provided for such projects is subject to change pending final execution of agreements. 10 o New wind resources totaling 265 MW;12
o New geothermal resources totaling 109 MW;
o New hybrid resources totaling 212 MW of solar generation and 153 MW of storage;
o New grid connected battery storage of 400 MW;
o New Demand Response resources of 15 MW; and
o New long-duration storage13 of 90 MW;
● MCE’s PCP provides for the following overall resource mix in 2035:
o Large hydro-electric of 525 GWh;
o Imported hydro-electric of 120 GWh;
o Small hydro-electric of 69 GWh;
o Biogas/biomass of 46 GWh;
o Geothermal of 1,785 GWh;
o California wind of 1,014 GWh;
o Out-of-state wind of 250 GWh;
o Offshore wind of 400 GWh;
o California solar of 1,155 GWh;
o Distributed solar of 13 GWh;
o Hybrid solar and storage of 596 GWh; and
o Standalone battery storage of 2,117 MWh (capacity x duration). ● Using the 30 MMT scenario CSP calculator, MCE’s PCP would have 2030 emissions of

0.500 MMT and 0.514 MMT in 2035.14 This is lower than MCE’s assigned share of 2030 and 2035 emissions (0.848 MMT and 0.630 MMT, respectively). ● Using the 25 MMT scenario CSP calculator, MCE’s PCP would have 2030 emissions of

0.493 MMT and 0.492 MMT in 2035. This is lower than MCE’s assigned share of 2030 and 2035 emissions (0.640 MMT and 0.504 MMT, respectively). ● MCE’s PCP meets all Commission-provided reliability metrics. ● MCE’s PCP provides more than MCE’s load-proportional share of renewable integration resources.

MCE has selected its PCP because it appropriately balances Board directives, MCE’s program 12 This 265 MW of new wind resources consists of in-state, out-of-state, and off-shore wind in the following amounts: 100 MW of in-state wind; 70 MW of out-of-state wind; and 95 MW of off-shore wind. 13 MCE is currently interested in long-duration storage resources with at least 8 hours of duration at full capacity. 14 MCE notes that the increase in emissions from 2030 to 2035 results from an increase in use of system power attributable to a decrease in allocated generation from Combined Heat and Power resources, as well as increases in the volume of curtailments and exports modeled.
11 goals, cost constraints, reliability, and customer rate impacts. Specifically, the PCP adheres to MCE Board Policy to achieve an 85% renewable energy content by 203515 and minimize GHG emissions through use of a combination of renewable energy and other low carbon energy sources.16
To implement its PCP, MCE is adopting the Action Plan described in Section IV, below. This Action Plan includes the following steps:
● MCE will conduct an annual “open season” Request for Offers (“RFO”) process to solicit offers for new renewable generation and storage projects. These resources are typically secured through long-term PPAs. MCE expects to secure PPAs for new projects in each open season conducted over the next several years; ● Periodically throughout the year, MCE will solicit offers for (i) short-term renewable energy, (ii) large hydro-electric and Asset Controlling Supply (“ACS”), (iii) RA, and (iv) load-hedging products needed to balance the portfolio and adhere to position limits established through MCE’s risk management policy and practices. These solicitations can take the form of formal RFO processes, bilateral discussions, and transactions arranged through broker markets; and
● Continuing to develop and offer customer programs that shed load, including aggregated load shift from business and residential customers.

II. Study Design
a. Objectives
MCE had the following objectives in performing the analytical work to develop its PCP and larger Compliance IRP:

1. Identify a portfolio that meets MCE’s goals for renewable energy utilization and GHG emission minimization and that has GHG emissions no greater than MCE’s proportional share of the 38 MMT 2030 GHG Emissions Benchmark and 25 MMT 2035 GHG Emissions Benchmark, as determined using the CSP calculator;

2. Identify a portfolio that achieves economic, reliability, environmental, security, and 15 This assumes a certain amount of curtailment as dictated by the CSP. Without the curtailments assigned by the CSP calculator, MCE’s renewable generation would be approximately 87%. To account for curtailment, MCE uses short-term contracts to balance its portfolio and meet its goals and obligations. This ensures that unrealized or curtailed generation is accounted for.
16 See MCE’s 2022 Operational Integrated Resource Plan available here: https://www.mcecleanenergy.org/energy-procurement/. 12 other benefits and performance characteristics that are consistent with the goals set forth in Section 454.52(a)(1) (A-I);

3. Identify a diverse and balanced portfolio that includes both short-term and long-term electricity, electricity-related, and demand reduction and management products;

4. Identify a portfolio that achieves the RA requirements established pursuant to Section 380 and fully provides MCE’s share of system reliability and renewable integration resources;

5. Identify a portfolio that fully complies with all MCE Board-adopted procurement directives;

6. Identify portfolios that are fully compliant with MCE’s obligations under the Renewable Portfolio Standard (“RPS”) program; and

7. Identify portfolios that are cost-effective and minimize rate impacts on MCE’s customers.
b. Methodology
i. Modeling Tool(s)
In developing its PCP, MCE used modeling tools that quantify portfolio targets for renewable energy content, capacity, and portfolio GHG emissions, as well as physical and financial positions to ensure adherence to MCE’s risk management policies and business practices. MCE uses proprietary models to assess annual, monthly, and hourly open positions taking into account forecasted hourly electric loads and expected deliveries from MCE’s resource portfolio.

MCE uses a proprietary financial model to project power supply costs and incorporate existing and planned procurement into an overall financial assessment of revenues, costs, and cash flows. MCE also utilizes a commercially available energy trading and risk management system to monitor positions, market exposure, credit exposure, value-at-risk, and other risk management metrics.17
Portfolio reliability was evaluated using forward-looking Effective Load Carrying Capacity (“ELCC”) values for each resource type to assess total NQC of the portfolio relative to MCE’s reliability requirements. This approach ensures MCE contributes to grid reliability commensurate with its share of system reliability needs.

For new resource selection where specific projects have not yet been identified in MCE’s procurement process, MCE relied upon the modeling and assumptions in RESOLVE as well as MCE’s recent procurement experience. Both provide insight into resource availability and cost. 17 Hitachi Energy TRMTracker.

MCE considered resource cost as well as portfolio fit (i.e., how new resources would complement existing portfolio resources to reliably serve MCE's load shape, while minimizing GHG emissions).

GHG emissions were assessed using t he Commission's CSP calculator for the 30 MMT and 25 MMT variat ions.
ii. Modeling Approach
Load Forecast
MCE developed its Compliance IRP using its assigned load forecast pursuant to t he June 15, 2022, Administrative Law Judge's Ruling Finalizing Load Forecasts and Greenhouse Gas Benchmarks for 2022 Integrated Resource Plan Filings ("Load Forecast Ruling"). MCE' s assigned load forecast used in this Compliance IRP is as follows:

Table 1: M CE's 2023-2035 Load Forecast
Year Load Forecast
(GWh}
2023 5,729
2024 5,759
2025 5,756
2026 5,759
2027 5,767
2028 5,795
2029 5,827
2030 5,955
2031 5,983
2032 6,040
2033 6,040
2034 6,067
2035 6,099
Load Shape
In developing its portfolio MCE used the default load shape from the CSP calculator. The use of this load shape does not change MCE's tot al annual energy volumes for both load and load modifiers, and these energy volumes remain consistent wit h MCE's assigned load forecast. 13 14
Compiling Existing Resources
To populate its baseline resource templates, MCE added existing resources from the following sources:
● Existing and planned energy contracts, including MCE’s election of renewable resources through the Voluntary Allocation and Market Offer (“VAMO”) process; ● Existing and planned capacity RA contracts;
● MCE’s assigned share of capacity for CAM and Demand Response resources, taken from the most recent year-ahead CAM resource allocations provided to MCE on September 29, 2022;18 and
● Expected allocations of GHG-free energy from the Pacific Gas & Electric Company (“PG&E”) portfolio.

Selecting New Resources
To identify its new resource procurement, MCE first determined the new resource capacity it intends to add each year. To make this determination, MCE considered (i) resource need (i.e., open positions), (ii) long-term renewable contracting requirements, (iii) RPS requirements, (iv) RA requirements, (v) the need for incremental RA capacity to contribute to system reliability and renewable integration needs, (vi) the potential for technological improvements, (vii) financial considerations, and (viii) a desire to transition its portfolio toward greater use of renewable energy and storage capacity in lieu of reliance on fossil resources. MCE selected resource types based on its experience with competitive solicitations for new renewable and storage resources as well as by making reference to the studies and modeling underlying the adopted PSP portfolio.

Confirming Reliability
MCE’s portfolios were evaluated to ensure that sufficient dependable NQC is available to meet peak load requirements plus the required planning reserve margin. MCE used forward looking technology specific ELCC factors provided by the Commission to assess the contribution of each resource to system reliability. As such, MCE’s portfolio addresses the expected changes to ELCC factors and NQC of its planned resources. MCE’s PCP was designed to ensure that current incremental RA capacity obligations are met, and that MCE contributes to new resource 18 MCE’s CAM and Demand Response allocations reflect the information provided in the Aggregated CAM Resources for LSEs Plan Development (“Aggregated CAM Guidance”), issued September 29, 2022, available at https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/2022-irp-cycle-events-and-materials. development to address fossil f uel ret irements, the decommissioning of t he Diablo Canyon Power Plant ("DCPP"),
19 and integration of renewable resources.

Calculating GHG Emissions
MCE calculated the emissions associated with its PCP using the Commission's CSP calculators.

The assigned load forecast, default load shapes, and behind-the-meter adjustments were used for t his assessment, along with the planned supply portfolio. MCE's PCP results in 2030 emissions of 0.500 MMT and 0.514 MMT in 203520 under the 30 MMT scenario, and 2030 emissions of 0.493 MMT and 0.492 MMT in 2035 under t he 25 MMT scenario.

Ill. StudyResults
~ Conform ing and Alternative Portfolios
Pursuant to Commission direction,21 MCE is submitting one PCP because this portfolio meet s the requirement s of both t he 30 MMT and 25 MMT system plans. As required, MCE presents this singular PCP separat ely in both the 30 MMT and 25 MMT RDTs and CSP calculators, respectively.

MCE is not presenting Alternative Portfolios.

To meet MCE's proj ected 2035 electricity demand of 6,099 GWh, MCE has selected a 2035 PCP composed primarily of the resource types and energy volumes detailed below. 22 Table 2: MCE's 2035 PCP Resources
Resource Under Owned or Planned Planned Under Total
Category Development Contracted Existing New Review
Battery Storage
(GWh Energy 24 - - 2 -
Capacity)
Biogas (GWh) - 30 - - - 30
19 Pursuant to Senate Bill 846, MCE's planning for purposes of this Compliance IRP assumes t he current retirement and decommission ing schedule for DCPP.
20 MCE notes t hat t he increase in emissions from 2030 t o 2035 results from an increase in use of system powe r attributable to a decrease in allocated gene rat ion from Combined Heat and Power resources, as we ll as increases in the volume of curtailments and exports modeled .
21 Load Forecast Ruling issued June 15, 2022 .
22 Residual ene rgy needs are assumed t o come from unspecified syst em e ne rgy purchases. 15 16
Biomass (GWh) - - 16 - - 16
Geothermal
(GWh) - - 149 580 1,056 1,785
Hybrid or Paired
Solar and Battery
(GWh)
596 - - - - 596
Imported Hydro
(GWh) - - 120 - - 120
Large Hydro
(GWh) - 25 500 - - 525
Small Hydro
(GWh) - 37 32 - - 69
Solar Distributed
(GWh) 13 - - - - 13
Solar Existing
California (GWh) 18 1,058 79 - - 1,155
Wind Existing
California (GWh) - - 374 - 87 461
Wind New
Mexico (GWh) - - - 250 - 250
Wind New PG&E
(GWh) 290 - - - - 290
Wind Offshore
Morro Bay (GWh) - - - 400 - 400
Wind New SCE
SDG&E (GWh) - - - - 263 263
17 Additionally, MCE’s 2035 PCP includes capacity-only resources composed primarily of the following:
● CAM, and Demand Response allocations – 48 MW23
● Existing natural gas and other (planned procurement) – 549 MW MCE’s portfolio includes a mix of existing and new resources. MCE’s 2035 portfolio is composed of approximately 1,383 MW of new nameplate capacity, reflecting MCE’s role as an active participant in the State’s development of new renewable and storage resources. Additionally, MCE’s short- and long-duration storage, along with its capacity-only resources will help maintain MCE’s commitment to supporting the State’s need for reliability and renewable integration.

MCE’s PCP Is Consistent with the 2021 PSP
The new resources included in MCE’s PCP are generally consistent with the 2021 PSP’s 2035 new resource mix as adopted in D.22-02-004, as updated,24 for both the 38 MMT and 30 MMT scenarios. There are, however, certain notable differences that reflect portfolio needs and resource selection that are unique to MCE.

As demonstrated in Table 3, below, MCE’s PCP includes proportionately more new resources than would be indicated by MCE’s proportional share of new procurement for each of the resource types identified in the adopted 2021 PSP.25 Under this scenario, MCE’s portfolio includes considerably more wind, geothermal and storage resources, and less utility-scale solar resources than does the 38 MMT PSP scenario.

Importantly, Table 3 also demonstrates the PCP’s general consistency with procurement types and amounts in the 30 MMT PSP scenario. Notably, however, MCE’s PCP consists of fewer MW of procurement and different resource proportions relative to the 30 MMT PSP 23 MCE’s CAM and Demand Response allocations reflect the information provided in the Aggregated CAM Guidance issued September 29, 2022.
24 LSE Plan Filing Requirements RESOLVE Modeling Results at 16, issued June 15, 2022, available at https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2022-irp-cycle-events-and-materials/lse-filing-requirement-resolve-results.pdf. 25 D.22-02-004 adopts the 38 MMT GHG target as the 2021 PSP. However, the Decision also requires LSEs to submit plans for how they would reach the 30 MMT GHG target or lower. Further, as clarified in the Administrative Law Judge’s Ruling Finalizing Load Forecasts and Greenhouse Gas Emissions Benchmarks for 2022 Integrated Resource Plan Filings, issued June 15, 2022, LSEs whose portfolios go below the 30 MMT GHG target are only required to submit one PCP.
scenario. Despite t hese deviations, MCE' s PCP: (a) meets t he lower emissions targets in t he 30 MMT PSP scenario as demonstrated in MCE's CSP tool, (b) meets MCE's projected load and energy needs as ref lected in Table 2, and (c) meets the reliability requirements as demonstrated in the Re liability t abs in MCE's RDTs and Section 111.f, below. This is due to MCE's PCP being weighted more heavily towards procurement of resources wit h high-capacity factors and being substantially less reliant on utility scale solar, which is assigned a significant ly lower capacity factor. The PCP reflects MCE's plans to invest in clean baseload, wind, and storage resources over t he course of t he planning horizon t hat complement t he existing level of solar resources in MCE' s portfolio. M CE sees t his portfolio as being t he most efficient and cost-effective means of meeting MCE' s emissions and reliability needs.

Table 3: M CE's PCP New Resource Procurement by Type Compared to 2021 PSP Resource 38 MMT PSP M CE Load- 30MMT PSP MCE Load- MCE's PCP Type Scenario New Proportional Scenario New Proportional (M W) Resources Share of 38 Resources (MW)27 Share of 30 MMT
(MW)26 MMT PSP New PSP New
Resources (MW) Resources
(MW)
Natural Gas 0 0 0 0 0
Biomass 134 4 134 4 0
Geothermal 1,135 30 1,135 30 109
Wind 3,562 95 4,270 114 191
Wind on New
Out-of State 4,636 124 4,828 129 70
Transmission
Offshore 4,707 126 4,707 126 95 Wind
26 As described in the filing requirements provided by the Commission, this PSP portfolio is referred to in other contexts as the 30 MMT Conforming Portfolio.
27 As described in the filing requirements provided by the Commission, this PSP portfolio is referenced in other contexts as the 25 MMT Conforming Portfolio.
18 19
Utility-Scale
Solar 17,418 465 21,794 582 22228
Battery
Storage 17,350 463 17,742 474 559
Pumped
(Long-Duration)
Storage
1,000 27 1,000 27 90
Shed Demand
Response 977 26 767 20 15
Total 50,919 1,360 56,377 1,505 1,351
The differences between MCE’s share of the 2021 PSP New Build Resources and the resources in MCE’s PCP, under either the 38 MMT or 30 MMT scenarios, reflect MCE’s planned contributions to new resource development during the planning period. MCE plans to add significant new renewable generation and storage capacity to help reduce reliance on fossil fueled generation, while minimizing GHG emissions and maintaining reliability using the most cost-effective and efficient portfolio of resources.
b. Preferred Conforming Portfolio
MCE’s PCP consists of a combination of:
● Utility-scale solar;
● In-state wind;
● Out-of-state wind;
● Off-shore wind;
● Short-duration storage;
● Long-duration storage;
● Small and large hydro-electric;
● Geothermal;
● Biomass/biogas;
● Shed Demand Response; and
● Natural gas/other (capacity only).
28 This represents 212 MW of solar hybrid procurement and 10 MW of new utility-scale solar procurement. 20 MCE’s PCP consists of the following specifical compilation of resources:
● MCE’s PCP includes the procurement of the following new resources and nameplate capacities over the course of the planning horizon:
o New wind resources totaling 265 MW (consisting of in-state, out-of-state, and off-shore wind);
o New geothermal resources totaling 109 MW;
o New hybrid resources totaling 212 MW of solar generation and 153 MW of storage;
o New grid connected battery storage of 400 MW;
o New Demand Response resources of 15 MW; and
o New long-duration storage29 of 90 MW;
● MCE’s PCP provides for the following overall resource mix in 2035:
o Large hydro-electric of 525 GWh;
o Imported hydro-electric of 120 GWh;
o Small hydro-electric of 69 GWh;
o Biogas/biomass of 46 GWh;
o Geothermal of 1,785 GWh;
o California wind of 1,014 GWh;
o Out-of-state wind of 250 GWh;
o Offshore wind of 400 GWh;
o California solar of 1,155 GWh;
o Distributed solar of 13 GWh;
o Hybrid solar and storage of 596 GWh; and
o Standalone battery storage of 2,117 MWh (capacity x duration).

As stated above, in accordance with Section 454.51(b)(3), the resource mix in MCE’s PCP achieves “economic, reliability, environmental, security, and other benefits and performance characteristics that are consistent with the goals set forth in [Section] 454.51(a)(1)].” These benefits and characteristics are discussed below.

Meeting GHG Reduction Goals
MCE’s PCP achieves results and performance characteristics consistent with the Section 454.52(a)(1)(A) goal of meeting the Commission’s 30 MMT or 25 MMT GHG reduction benchmark. MCE’s proportional share of the 30 MMT benchmark is 0.848 MMT in 2030 and

0.630 MMT in 2035. According to the Commission’s emissions calculator for the 30 MMT 29 MCE is currently interested in long-duration storage resources with at least 8 hours of duration at full capacity. 21 scenario, MCE’s PCP would account for 0.500 MMT of emissions in 2030 and 0.514 MMT of emissions in 2035.30 MCE’s proportional share of the 25MMT benchmark is 0.640 MMT in 2030 and 0.504 MMT in 2035. According to the Commission’s CSP calculator for the 25 MMT scenario, MCE’s PCP would account for 0.493 MMT of emissions in 2030 and 0.492 MMT of emissions in 2035.

Procuring Eligible Renewable Energy
MCE’s PCP achieves results and performance characteristics consistent with the goals of Sections 454.52(a)(1)(B) & (F) of ensuring that portfolios are composed of at least 50% eligible renewable resources and displacing fossil fuels within the state. In 2035 MCE’s PCP portfolio would consist of 87% eligible renewable generation. To this end, MCE has executed a number of long-term PPAs with new, California-based generating facilities that will produce Portfolio Content Category (“PCC”) 1-eligible renewable energy in excess of the 2030 requirement. Of the targeted 87% eligible renewable generation in 2035, 44.5% is under long-term contracts in 2030, and 33.6% in 2035. The remaining 42.5% and 53.4%, respectively, will be filled with long-term contracts that are currently under negotiations and/or planned as shown in both the CSPs and RDTs.31
To supplement its core procurement of PCC 1 resources under long-term contracts for its PCP, MCE engages, and will continue to engage, in short-term contracts for renewable energy supplies to balance and optimize its PCP. As of this filing, MCE has secured contracts for renewable energy volumes in excess of applicable California RPS procurement requirements through 2025, and long-term contracting requirements through 2030.

Minimizing Bill Impact
MCE’s PCP achieves results and performance characteristics consistent with the Section 454.52(a)(1)(D) goal of minimizing the impact of planned procurement on ratepayers’ bills. MCE prioritizes use of renewable energy and low carbon emitting resources, reliability, and cost competitiveness.
30 MCE notes that the increase in emissions from 2030 to 2035 results from an increase in use of system power attributable to a decrease in allocated generation from Combined Heat and Power resources, as well as increases in the volume of curtailments and exports modeled.
31 Historically, MCE has contracted with PCC 1 resources located in California. However, some resources located outside California are eligible for PCC 1, typically through direct interconnection or firm transmission rights to the CAISO. Although MCE has an established preference for in-state resources, contracting with out-of-state PCC 1- qualified resources is likely to the extent that they offer increased value or other desirable portfolio attributes during the planning period.
22 Energy and RA costs have risen sharply in recent years, and rising wholesale energy costs have placed upward pressure on customer rates. New build renewable development and storage costs have also seen substantial increases since the last IRP cycle due to a confluence of unprecedented amounts of mandated procurement on strict timelines, limited transmission capacity to support new projects, supply chain constraints, and inflationary pressures. At the same time, prices in the short-term markets for renewable energy and RA have also increased significantly resulting from increasing incidents of resource scarcity during peak hours and more numerous and extensive extreme weather events. MCE will take steps to minimize bill impacts, but near-term rate increases may be necessary to accommodate increased procurement costs.

Despite recent cost increases for new generation and storage associated with its resource plan, bill impacts can be at least partially mitigated by the fact that new renewable generation projects can have lower net costs than the prices paid in the short-term renewable energy and resource adequacy markets. In evaluating new resource commitments, MCE seeks generation and/or storage projects that meet portfolio fit considerations and that have positive net present value in consideration of expected contract costs and the value of the energy, reliability, and environmental attributes provided by the project. Such projects help reduce costumer costs relative to alternative sources of energy and capacity. Further, MCE’s PCP minimizes exposure to volatile natural gas prices and the bill impacts that can result from periodic spikes in fossil fuel prices.

Specific estimates of MCE’s average portfolio costs through 2035 are provided in Section III.e., below.

Ensuring System and Local Reliability
MCE’s PCP achieves results and performance characteristics consistent with the Section 454.52(a)(1)(E) goal of ensuring system and local reliability on both a near- and long-term basis.

The PCP meets system RA requirements as detailed in Section III.f. MCE’s PCP is reliable from both an MCE-specific and systemwide perspective under the 30 MMT and 25 MMT Scenarios.

The PCP would provide adequate energy storage and RA capacity to meet MCE’s generation needs during non-solar generating hours.

As a practical matter, the ability of MCE’s portfolio to meet MCE’s own load requirements will not be materially impacted by whether other parties procure consistent with the 30 MMT or 25 MMT target. As discussed in Section III.f., MCE’s PCP includes sufficient NQC to meet peak loads and reserve margins regardless of whether other load serving entities procure to the 25 MMT or 30 MMT benchmark targets. If other LSEs procure in accordance with a 25 MMT GHG target, the NQC and contribution to reliability of MCE’s PCP would increase by an average of 10 MW. 23 Based on results from the CSP calculator, MCE should expect more hours of curtailment for its renewable resources, greater use of system power, and higher emissions of GHG and local pollutants in the 30 MMT scenario as compared to the 25 MMT scenario; however, these differences are small relative to the size of MCE’s planned portfolios and would have no meaningful impact on reliability.

For the periods during which MCE’s load exceeds the sum of its contracted energy resources and planned storage capacity and Demand Response resources, MCE intends to ensure sufficient system capacity is available through use of firm short- and long-term RA contracts.

MCE is planning that approximately half of its RA capacity (ELCC adjusted) will be provided by new renewable and storage resources, while the other half will be provided by existing resources, most of which are likely to be dispatchable natural gas fueled generators.

MCE is proud of its role supporting reliability and renewable integration needs to date and is eager to continue supporting these important state objectives going forward. While MCE has built-in plans for traditional reliability resources (i.e., from natural gas), MCE aspires to gradually layer in reliability supply that better aligns with the State’s ultimate GHG reduction goals.

Strengthening the Bulk Transmission and Distribution Systems MCE’s PCP achieves results and performance characteristics consistent with the Section 454.52(a)(1)(G) goal of strengthening the diversity, sustainability, and resilience of the bulk transmission and distribution systems. MCE does not own, operate, or maintain the bulk transmission or distribution systems. However, MCE’s procurement of strategically located renewable generation, prioritization of local renewable generation, demand-side management efforts, and investment in distribution-side resources all serve to enhance the sustainability and resiliency of the bulk transmission and distribution systems.

Enhancing Demand-Side Energy Management
MCE’s PCP achieves results and performance characteristics consistent with the Section 454.52(a)(1)(H) goal of enhancing demand-side energy management. MCE’s PCP includes MCE’s allocation of capacity through the demand-side management programs operated by PG&E.

MCE operates a variety of energy efficiency and demand response programs, including MCE’s PeakFlex Market.32
Additionally, MCE is working to develop a pilot Virtual Power Plant (“VPP”) within the City of 32 See https://www.mcecleanenergy.org/market/ .
24 Richmond. This effort will install a suite of privately-owned distributed energy resources (“DERs”) to be dispatched into the VPP, such as rooftop solar, heat pump water heaters, smart thermostats, smart plugs, electric vehicles, and energy storage. These will send data directly to MCE and can be remotely controlled and operated together to pull power to and from the grid at strategic times, creating pockets of power to support and decarbonize the grid.

The goal of Richmond Advanced Energy Community is to connect 120 sites to the VPP including 10 rehabilitated homes, 90 homes occupied by low-to-middle income residents (which have already received solar systems from GRID Alternatives), 18 commercial sites, and 2 industrial sites. Combined, the 120 sites are expected to contribute 1 MW of solar, 2 MWh of energy storage, and 1.5 MW of flexible load by December 2024.

The VPP will allow MCE to aggregate and dispatch DERs to manage critical peak loads, minimize procurement costs, and - as market opportunities evolve - generate value in wholesale markets.

Participants may not be enrolled in other DER aggregation or demand response programs.

Participants will receive modern appliances, bill savings, and bill credits.

MCE plans to expand this program to monitor and control other customer owned DERs.

Minimizing Localized Air Pollutants with Emphasis on Disadvantaged Communities MCE’s PCP achieves results and performance characteristics consistent with the Section 454.52(a)(1)(I) goal of minimizing localized air pollutants and other GHG emissions with early priority on disadvantaged communities (“DACs”). MCE’s PCP relies primarily on renewable generation and would have low GHG and localized air pollution emissions. Further, MCE’s PCP minimizes MCE’s reliance on unspecified system power, instead opting for renewable generation, hydro generation, local energy storage, and local demand side reduction programs.

Results from the 30 MMT CSP calculator indicate the following localized air pollutants associated with MCE’s PCP in 2035:
● NOx: 68 tonnes/yr
● PM 2.5: 31 tonnes/yr
● SO2: 7 tonnes/yr
Results from the 25 MMT CSP tool indicate the following localized air pollutants associated with MCE’s PCP in 2035:
● NOx: 64 tonnes/yr
● PM 2.5: 28 tonnes/yr
• SO2: 7 tonnes/ yr
These emissions derive primarily from system energy and CHP resources assigned to the MCE portfolio by the CSP calculator, as well as from relatively small amounts of biogas/ biomass resources included in the PCP. MCE' s four existing biogas energy sources are not located in DACs as identified in CalEnviroScreen 4.0. MCE plans to include emissions impacts on DACs as one of t he criteria used for selecting specific proj ects for any procurement that may be assigned emissions.
c. GHG Emissions Results
GHG emissions associated with MCE's PCP are shown below for the 30 MMT and 25 MMT Scenarios. As stated above, t he emissions associated with MCE' s PCP are lower t han MCE's proportional share for both the 30 MMT and 25 MMT benchmarks.

Table 4: MCE's PCP GHG Emissions
Scenario
Emissions Unit 2024 2026 2030
Total
30MMT CO2 MMt/yr 0.277 0.380 0.500
25MMT CO2 MMt/yr 0.265 0.390 0.493
fl. Local Air Pollutant Minimization and Disadvantaged Communities i. Local Air Pollutants
2035

0.514

0.492
Local pollutant emissions associated with MCE's PCP are shown below for the 30 MMT and 25 MMT Scenarios:
30 MMT Scenario
Table 5: MCE's PCP Local Pollutant Emissions (30 MMT Scenario) Emissions Unit 2024 2026 2030 2035
Total
PM2.5 tonnes/ yr 39 35 34 31
SO2 tonnes/ yr 18 15 12 7
NOx tonnes/ yr 137 116 97 68
25 25 MMT Scenario
Table 6: M CE's PCP Local Pollutant Emissions (25 MMT Scenario) Emissions Unit 2024 2026 2030 2035
Total
PM2.5 tonnes/yr 38 34 33 28
S02 tonnes/yr 18 15 12 7
NOx tonnes/yr 137 114 95 64
In each scenario, local air pollutant s associat ed wit h MCE's electricity mix are proj ected to decrease. As described in MCE's Action Plan, below, MCE intends to reduce its reliance on syst em power by procuring the renewable and ot her low GHG-emitting resources ident ified in its PCP. MCE actively seeks out power supply t echnologies t hat minimize air pollutants including fully renewable technologies as well as hydro-electric and natural gas/battery hybrid technologies.
ii. Focus on Disadvantaged Communit ies
MCE's PCP is fully consistent with the goal of minimizing local air pollut ants, wit h early priority on DACs.

MCE's programs illustrate t hat MCE t akes an expansive view of its responsibilities in t his area and takes efforts to minimize disadvantaged community air pollution impacts, not only in its own service area, but also in the state as a whole.

As identified by CalEPA's designation,
33 MCE serves t he following DACs:

Table 7: DACs Served by M CE
Census Tract Nearby City California ZIP Total M CE MCE Non- MCE County Code Population Residential Residential Accounts in Accounts in Accounts in Census
Census Tract Census Tract Tract
6013305000 Antioch Contra Costa 94509 6561 1 104 105
6013307202 Antioch Contra Costa 94509 4299 0 2 2
33 SB 535 Disadvantaged Communities I OEHHA (ca.gov).
26 27
6013314103 Bay Point Contra Costa 94565 5629 1,552 61 1,613 6013314104 Bay Point Contra Costa 94565 9278 2,217 121 2,338 6013336201 Concord Contra Costa 94520 4056 1,161 21 1,182 6013320001 Martinez Contra Costa 94553 3671 1,092 262 1,354 6013365002 North Richmond Contra Costa 94801 5590 1,213 126 1,339 6013302005 Oakley Contra Costa 94561 7290 2,051 184 2,235 6013309000 Pittsburg Contra Costa 94565 3546 1,275 175 1,450 6013310000 Pittsburg Contra Costa 94565 6257 1,646 135 1,781 6013311000 Pittsburg Contra Costa 94565 5329 1,473 67 1,540 6013312000 Pittsburg Contra Costa 94565 2243 626 82 708 6013313101 Pittsburg Contra Costa 94565 7178 2,580 491 3,071 6013313102 Pittsburg Contra Costa 94565 4595 1,341 123 1,464 6013314102 Pittsburg Contra Costa 94565 6561 1,184 33 1,217 6013373000 Richmond Contra Costa 94801 4468 897 90 987
6013375000 Richmond Contra Costa 94801 4897 1,050 96 1,146 6013376000 Richmond Contra Costa 94801 6245 1,557 78 1,635 6013377000 Richmond Contra Costa 94801 7323 2,123 168 2,291 6013379000 Richmond Contra Costa 94804 7003 1,508 203 1,711 6013380000 Richmond Contra Costa 94804 5931 2,860 380 3,240 6013381000 Richmond Contra Costa 94804 6521 1,708 191 1,899 6013382000 Richmond Contra Costa 94804 8159 1,540 114 1,654 6013392200 Richmond Contra Costa 94806 11304 2,829 172 3,001 6013358000 Rodeo Contra Costa 94572 6285 1,609 151 1,760 6013364002 San Pablo Contra Costa 94806 5531 1,693 36 1,729 28 6013366001 San Pablo Contra Costa 94806 4514 1,117 34 1,151 6013366002 San Pablo Contra Costa 94806 6627 1,584 71 1,655 6013368001 San Pablo Contra Costa 94806 4817 1,236 85 1,321 6013368002 San Pablo Contra Costa 94806 3782 956 125 1,081 6013369001 San Pablo Contra Costa 94806 7254 2,026 240 2,266 6013314200 Unincorporated
Contra Costa
County Area
Contra Costa 94565 7748 1,473 50 1,523
6013315000 Unincorporated
Contra Costa
County Area
Contra Costa 94520 3862 1,077 811 1,888

6013327000 Unincorporated
Contra Costa
County Area
Contra Costa 94520 7430 1,627 1,001 2,628
6095252502 Fairfield Solano 94533 2106 596 281 877
6095250801 Unincorporated
Solano County
Area
Solano 94592 4135 1,079 45 1,124
6095252402 Unincorporated
Solano County
Area
Solano 94534 5549 1,470 361 1,831
6095253500 Unincorporated
Solano County
Area
Solano 94571 10676 308 323 631
6095250701 Vallejo Solano 94590 3529 767 196 963
6095250900 Vallejo Solano 94590 2654 1,133 344 1,477
6095251000 Vallejo Solano 94590 2654 1,122 69 1,191
6095251200 Vallejo Solano 94590 3663 1,068 222 1,290
6095251500 Vallejo Solano 94590 4326 1,362 348 1,710
6095251600 Vallejo Solano 94590 2580 1,086 123 1,209
6095251802 Vallejo Solano 94589 2770 927 406 1,333
29 6095251901 Vallejo Solano 94589 5119 1,626 73 1,699
6095251902 Vallejo Solano 94589 6173 1,508 59 1,567
In total, MCE serves 54,897 customer accounts located within DACs. This represents approximately 9.5% of MCE’s total customer accounts (approximately 580,000).

MCE is dedicated to reducing pollution impacts and encouraging the development, health, and prosperity of DAC within and outside our service area. Our commitment is reflected in the practices, programs, and policies described below.

Green Access and Community Solar Connection Programs
MCE is collaborating with the Commission, Investor-owned Utilities (“IOU”), and other CCAs to develop community solar programs for customers in DACs. These programs will be supported by the development of an additional 5.92 MW of new, local, clean energy capacity.

The Green Access program will supply 100% renewable power to customers located in a DAC with an accompanying 20% bill discount. The program currently serves 3,000 customers, and MCE prioritizes customers who live in the highest scoring DACs and are currently participating in either the California Alternate Rates for Energy (“CARE”) or Family Electric Rate Assistance (“FERA”) discount program and need additional support to get caught up on their energy bills.

Eligible customers will be served by this 4.64 MW solar resource once it comes online, currently expected by December 2023.

The Community Solar Connection program will offer 100% solar energy and provide a 20% discount on the electricity portion of participating customers’ energy bills. This program also involves developing a solar project within 5 miles of a DAC to serve participating customers. At least 50% of the program’s participation capacity will be reserved for customers who are enrolled in CARE or FERA discount programs. Efforts to procure the 1.28 MW solar resource for this program are currently ongoing.

MCE estimates that it will be able to provide approximately 3,500 customers in DACs with bill discounts after both programs are up and running.

I I
30 Sustainable Workforce and Diversity Policy
In 2017, MCE’s Board approved a Sustainable Workforce and Diversity Policy34 to facilitate and encourage diversity and a sustainable workforce through its support for the following:

1. Fair compensation in direct hiring, renewable development projects, customer programs, and procurement services;

2. Development of locally generated renewable energy within the MCE service area;

3. Direct use of union members from multiple trades;

4. Quality training, apprenticeship, and pre-apprenticeship programs;

5. Direct use of local businesses in MCE’s service area;

6. Development of California-based job opportunities;

7. Business and workforce initiatives located in low-income and disadvantaged communities;

8. Direct use of Disabled Veteran-owned Business Enterprises (“DVBE”) and LGBT-owned Business Enterprises (“LGBTBE”);

9. Direct use of green and sustainable businesses; and

10. Direct hiring practices that promote diversity in the workplace.

More recently, in 2022 MCE adopted Sustainable Workforce Guidelines35 to create a more detailed plan for implementing its Sustainable Workforce and Diversity Policy, further demonstrating our commitment to procuring resources that benefit our customers, our planet, and our future. These guidelines outline how MCE integrates these priorities into PPAs with third parties, MCE-owned or MCE-led power generation projects, and MCE customer programs, services, supplies, and direct hiring. For example:
● When possible, MCE shall give preference to projects within MCE’s service area and to CBOs and local associations serving disadvantaged and low-income communities. ● MCE has three tiers of requirements for union labor depending on the location of proposed projects. Projects located in Contra Costa County and over 1 MW in size must adhere to the terms of the Project Labor Agreement (“PLA”) between MCE and International Brotherhood of Electrical Workers (“IBEW”) Local 302 (“MCE/IBEW PLA”).

Projects within Napa, Marin, or Solano County must participate in a PLA of similar 34 See MCE November 16, 2017, Board of Directors Meeting Packet, Agenda Item No. 7 Attachment A https://www.mcecleanenergy.org/wp-content/uploads/2020/05/MCE-Board-Meeting-Packet-November 2017.pdf. 35 See https://www.mcecleanenergy.org/wp-content/uploads/2022/05/MCE-Sustainable-Workforce-Guidelines 05122022.pdf. 31 scope and requirements with participating unions for workforce hired as described in the MCE/IBEW PLA. Projects outside of MCE’s service area are encouraged to enter into project labor agreements of similar scope and requirements with participating unions for workforce as described in the MCE/IBEW PLA.
● For projects located in MCE’s service area, 50% of work hours are required to come from permanent residents who reside within the same county as the project. ● MCE will not accept any proposals for projects that rely on equipment or resources built with forced labor. MCE adopted this prohibition two years ahead of federal law, signed by President Biden in June 2022.
● Any renewable development project that is developed or owned by MCE qualifies as a public works project and requires prevailing wages to be paid.

These programs offer qualifying customers living in a CalEnviroScreen-designated DAC access to 100% renewable energy and a 20% discount on their electricity bills for up to 20 years. Both programs will be supported by the development of additional new clean energy resources.

Ad Hoc Workforce Development
Growing the green economy, supporting local contractors, and providing access to workforce development opportunities are core to MCE’s mission. One avenue for job creation is through energy efficiency, which lowers energy consumption and can save customers money while reducing greenhouse gas pollution and producing more equitable communities. Importantly, improving the built environment through energy efficiency also creates strong job opportunities, including among populations facing additional barriers to workforce entry.

Encouraging the creation of local green job opportunities is rooted in the history of MCE’s efforts to create more equitable communities, while also reducing GHG emissions through renewable energy projects and electrification of the built environment and the transportation sector. For example, MCE has:
● Partnered with the Marin City Community Development Corporation from 2012–2016 32 to train 59 community members and connect them to solar installation and energy efficiency jobs.
● Partnered with RichmondBUILD in 2013, 2015, and later in 2021 to help 44 job seekers develop construction, numeracy, and literacy skills, and later connect them with related jobs for MCE Solar One and an LED retrofit project for city streetlights. ● Partnered with Rising Sun Center for Opportunity in 2012 and 2016 to train youth to provide no-cost energy and water-saving assessments in the cities of Richmond, El Cerrito, and San Pablo. More recently in 2021–22, helped customize a Rising Sun training construction curriculum to train five cohorts on green construction basics and give them an intro to electrification and energy storage systems. ● Coordinated the installation of a new call center in the City of Pittsburg through its contract with Calpine in 2017, and then partnered with Future Build in Pittsburg (a county workforce development program) to train students on call center basics, call handling, energy data, and more. Graduates of the training were offered positions at the new call center.
● Partnered with GRID Alternatives in 2021 to train six job seekers from Marin City and the Canal District on solar installation skills and provided them a paid stipend for their participation, to increase access and minimize barriers. ● Sponsored a collaboration with Puertas Abiertas Community Resource Center to develop a direct connection between local hard-to-reach communities and the opportunity to inform and engage with these communities on MCE programs and services, especially those programs developed specifically for underserved populations.

This program sponsorship was a workforce development opportunity for organization staff to learn more about renewable energy, energy efficiency, and environmental sustainability.

To deepen MCE’s commitment to creating equitable green jobs, MCE has been an active participant in the regional High Road Training Partnership (“HRTP”) led by the Rising Sun Center for Opportunity since 2021. The joint project aims to understand regional decarbonization labor market demands, workforce issues, and training needs; establish industry labor standards; and develop clear, accessible training pathways to building decarbonization jobs in the Bay Area, especially for entry-level and disadvantaged workers.

Together with other key partners — including the Association for Energy Affordability, Electrify My Home, Inclusive Economics, Eco Performance Builders, Building Electrification Institute, Bay Area Metro, GENTEC Services, Emerald Cities Collaborative, StopWaste, the Greenlining Institute, Construction Trades Workforce Initiative, the Cities of Berkeley and Oakland and the Association of Bay Area Governments — MCE staff collaborate and hear from leaders in the ■
33 industry to address important equity and access aspects of a renewable economy. As a member of the Equity and Public Agencies Working Groups, MCE staff work to lay the groundwork for this industry while improving agency programming.

Creating Energy Efficiency Jobs
In 2018, the CPUC awarded MCE $2.24 million through 2025 to offer a broad spectrum of opportunities to prepare the local workforce for careers in energy efficiency. This funding allows MCE to streamline workforce investments into a sustainable pipeline of long-term green job opportunities for community members, while strengthening the local economy and contributing to a just transition to a clean energy economy. This path is especially important in communities where the fossil fuel industry has long been a primary employer for generations of families. To ensure that a decarbonized energy future provides economic opportunities for all, workforce programs like these are a necessary link to train for the skills needed to enter the green economy.

As a result, in 2020 MCE launched the Workforce, Education, and Training (“WE&T”) Program to create a geographically diverse pool of training partners able to provide job seekers with the skills necessary to be competitive in the energy efficiency and electrification sector. This program funds on-the-job training and up to 12 months of wrap-around services to support their transition to a new career in energy efficiency and electrification. While providing an onramp for job seekers, the WE&T Program concurrently allows vetted contractors working in MCE’s service area to be matched with these prequalified job seekers for 160 hours of no-cost project assistance and labor. By influencing both the supply side and demand side of this industry, MCE hopes to increase the number of skilled workers and strengthen the local labor market.

With engagement from local partners, community colleges, and the existing contractor workforce, MCE has developed an internship program to achieve the following goals:
● Upgrade the existing contractor workforce’s technical expertise on energy efficiency and electrification technology;
● Fund the training of job seekers;
● Match qualified job-seeker trainees with trained contractors and pay for a local internship in a “learn and earn” model; and
● Provide project site opportunities where the intern can install efficiency and electrification measures while helping MCE customers increase the efficiency, health, and safety of their homes and businesses.
34 Long term, MCE hopes to solidify this trainee-to-employee pipeline so that it can continue investing in technical training, creating onramps to career pathways, providing job security, and building the economic health of member communities.

Equity in Power Purchasing
As of 2021, MCE’s Open Season solicitation encourages suppliers to consider community benefits and equity metrics when submitting offers. Some of the optional elements that MCE solicits in offers include:
● Support for educational programs, environmental justice initiatives, and workforce development and training initiatives;
● Participation of contractors, subcontractors, or businesses owned by disabled veterans;
● Projects located in a designated DAC or employing workers living in a designated DAC; and
● Use of components and materials manufactured or assembled in the United States.

In late 2020, when issues related to the use of forced labor for solar equipment production in Xinjiang, China, were reported, MCE incorporated new language into its PPA term sheets and contracts that prohibit MCE from contracting with facilities that rely on equipment or resources built with forced labor. This language was incorporated into MCE’s 2021 and 2022 Open Season, Green Access, and Community Solar Connection PPAs, and will continue to be an MCE procurement requirement.

Strategic Recruiting and Hiring Practices
Practices include targeted job postings, partnerships with community-based organizations (“CBOs”), education and employment organizations, physical attendance at job recruitment fairs, blind resume reviews, and the creation of diverse hiring panels. Some MCE jobs may substitute experience for education requirements. MCE has also tailored employee benefit packages to be more inclusive and to apply to a broad range of people.

Community Power Coalition
To facilitate direct community collaboration in the development, progress, and evolution of its mission MCE engages its Community Power Coalition (“CPC”). Formed in 2014, the CPC seeks to represent the interests of underrepresented and historically marginalized communities through collaboration and open dialogue with MCE. The CPC currently has over 40 members and meets every two months. MCE’s recruitment for the CPC prioritizes organizations that:
35 ● Expand awareness and access to affordable renewable services; ● Accelerate the transition to a clean energy future through workforce development training opportunities;
● Develop inclusive programs and policies at MCE; and
● Identify just and equitable community collaboration opportunities aligned with MCE’s environmental justice values.

Adding these voices and their questions to the CPC working group deepens MCE’s understanding about the groups’ challenges and the measures or types of support that are needed. MCE’s CPC strengthens its connection to the community and offers expert advice on the needs of their constituents and how MCE can best support underserved customers and environmental equity through its programs, policies, and procurement.

Building Community Resiliency
To mitigate the impact of grid outages and Public Safety Power Shutoff (“PSPS”) events, and improve overall grid reliability, MCE’s Board of Directors approved a Resiliency Fund in 2019.

In 2020, MCE launched its Energy Storage Program to deploy up to 15 MWh of customer-sited battery storage systems that can provide backup power during grid outages and reduce GHG emissions and costs. This program prioritizes vulnerable customers and populations that are disproportionately affected by grid outages. The program leverages incentives from the CPUC’s Self-Generation Incentive Program (“SGIP”), coupled with gap funding and performance-based payments provided through MCE’s Resiliency Fund.

To extend the impact of this program, MCE is working with the Marin Community Foundation.

Through a three-year grant of $750,000 from the Buck Family Fund, this partnership is stretching MCE’s contributions to secure local resilience in Marin. These funds will be used to cover the costs for select critical facilities operated by nonprofits throughout Marin County to provide backup power to vulnerable communities during planned or unplanned outages.

As described above, on May 26th, 2022, MCE was approved to join the implementation of a $5 EPIC grant from the CEC to develop an Advanced Energy Community (“AEC”). The grant will be used to develop a pilot VPP within the City of Richmond. The goal of Richmond Advanced Energy Community is to connect 120 sites to the VPP including 10 rehabilitated homes, 90 homes occupied by low-to-middle income residents (which have already received solar systems from GRID Alternatives), 18 commercial sites, and 2 industrial sites. Combined, the 120 sites are expected to contribute 1 MW of solar, 2 MWh of energy storage, and 1.5 MW of flexible load by December 2024.
36 The VPP will allow MCE to aggregate and dispatch DERs to manage critical peak loads, minimize procurement costs, and - as market opportunities evolve - generate value in wholesale markets.

Participants may not be enrolled in other DER aggregation or demand response programs.

Participants will receive modern appliances, bill savings, and bill credits. During later phases, this program may help MCE expand its role as a California Independent System Operator (“CAISO”) market participant by aggregating resources that can be dispatched into the CAISO market.

COVID-19 Customer Support
In response to the COVID-19 pandemic, MCE launched additional programs and services to support its customers. The $10 million MCE Cares Credit Program offers qualifying customers bill relief in the form of a $10 monthly bill credit for residential customers and a 20% monthly bill credit for small businesses. This program pairs with state discount programs and the Arrearage Management Program (“AMP”), in which MCE was an early participant.

MCE’s ongoing COVID relief efforts include suspension of collections; direct outreach to customers to encourage enrollment in existing discount and utility bill assistance programs; an education and awareness program to spread the word about community resources and programs for financial assistance; and free EV charging at MCE’s San Rafael office. The relief efforts were promoted online, via social media, with signage, and through local business and residents groups from early 2020 through the summer of 2022. MCE also launched two webpages providing a comprehensive list of COVID support resources for residential and small business customers, by county. In 2021, MCE partnered with local CBOs to distribute bill-savings program flyers in English and Spanish. e. Cost and Rate Analysis
MCE strives to minimize carbon emissions associated with the electricity it supplies to customers while maintaining competitive rates and minimizing customer bill impacts. MCE also prioritizes reliability and seeks a supply portfolio that minimizes risks related to transmission congestion, curtailments, project development risks, and other uncertainties that impose the potential for unanticipated costs. MCE’s PCP was developed with these goals in mind.

Resources were selected for least cost and best portfolio fit based on associated emissions, delivery profile, risk, commercial viability, and reliability. MCE considers both the direct resource costs (e.g., contract price) as well as the value of each resource in its portfolio, taking into account the different resource characteristics of the various portfolio options. 37 MCE modeled the expected portfolio costs of its PCP to evaluate cost and rate impacts on customers. The results of this cost analysis are illustrated in the figure below. System average portfolio costs are projected to increase through 2024, decline from 2025 through 2028, and slowly increase from 2029 through 2035. The compounded annual rate of growth (nominal dollars) between 2022 and 2035 is 0.5%, which is below the expected rate of inflation. The near-term cost increases are primarily driven by high prevailing CAISO energy costs, which are influenced by the significant increase in natural gas prices since the beginning of 2022.

Exceptionally high resource adequacy costs are also driving increases in MCE’s average portfolio costs. These cost pressures are expected to moderate as new resources are developed and displace more expensive purchases from the short-term markets. It must be noted that the projected portfolio costs are dependent on assumed costs for new resources, and these are subject to considerable uncertainty. MCE engages in competitive solicitations for resource selection and makes resource decisions based on prices offered to it during these solicitations.

MCE has observed very little stability in offered resource prices over time as market conditions and external events such as procurement orders, trade tariffs, tax policy and supply chain conditions impact resource costs that are available at any point in time. If these events persist, or additional external events (e.g., new procurement orders) occur, the average portfolio costs may instead continue to increase in excess of MCE’s current projections. While MCE’s PCP provides a helpful framework for procurement decisions going forward, MCE must remain flexible to respond to market conditions or technological changes as circumstances change.

MCE will take steps to minimize bill impacts, but near-term rate increases may be necessary to accommodate increased procurement costs.

In evaluating new resource commitments, MCE seeks generation and/or storage projects that meet portfolio fit considerations and that have positive net present value in consideration of expected contract costs and the value of the energy, reliability, and environmental attributes provided by the project. Such projects help reduce consumer costs relative to alternative sources of energy and capacity.

New resources were selected for the PCP with the goal of minimizing ratepayer impacts, while meeting reliability and environmental policy goals. MCE’s plan diversifies across different renewable and low-carbon generation technologies with the goal of reducing use of system energy, thereby reducing market risk and emissions. MCE selected new resources that provide reliability and low emissions (e.g., geothermal) and other carbon-free technologies that have low expected costs (e.g., wind), which in conjunction with resources already under contract provide a least-cost, best-fit portfolio solution. In modeling expected ratepayer costs, MCE generally used cost assumptions consistent with RESOLVE modeling and the PSP. While not the lowest cost resource option, geothermal resources were included in the PCP to provide ■
38 reliability benefits from additional clean, firm resources. These resources have relatively low GHG emissions, and their ability to reliably produce energy on a near 24X7 basis warrants a role despite somewhat higher costs. Technological diversification in use of resources capable of providing firm energy reduces ratepayer risk that could arise from overdependence on new technologies such as long duration storage. The PCP includes lower cost wind resources to help minimize ratepayer impacts while meeting environmental and reliability objectives. MCE’s PCP also minimizes exposure to volatile natural gas and system power prices and the bill impacts that can result from periodic spikes in fossil fuel prices. f. System Reliability Analysis
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2 22 2 23 2 2 2 25 2 26 2 27 2 28 2 29 2 3 2 31 2 32 2 33 2 3 2 35 39 40
g. High Electrification Planning
Under a high electrification scenario, MCE’s energy and peak demand requirements would increase, with most of the increase occurring toward the latter end of the planning period.

MCE projected the load impacts of a high electrification scenario based on the 2022-2023 TPP High Electrification Load Sensitivity RESOLVE Modeling Results available on the 2019-2020 IRP Page.36
Assuming similar impacts within the MCE service territory, MCE’s adjusted load forecast is shown below:
36 https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/integrated-resource-plan-and-long-term-procurement-plan-irp-ltpp/2019-2020-irp-events-and-materials/2022-2023-tpp-high-electrification-sensitivity-resolve-results.pdf.

Table 8: MCE's 2024-2035 Load Forecast - High Electrification Scenario Year Retail Sales (MWh), Retail Sales (MWh), Impact of High Base Case High Electrification Electrification (MWh)
2024 5,759 5,759 -
2025 5,756 5,756 -
2026 5,759 5,759 -
2027 5,767 5,767 -
2028 5,795 5,843 48
2029 5,827 5,959 132
2030 5,955 6,176 221
2031 5,983 6,325 342
2032 6,040 6,507 467
2033 6,040 6,637 597
2034 6,067 6,802 735
2035 6,099 6,974 875
Table 9: M CE's 2024-2035 Peak Demand Forecast - High Electrification Scenario Year Annual Coincident Annual Coincident Impact of High Peak Demand (MW), Peak Demand (MW), Electrification (MW) Base Case High Electrification
Case
2024 1,273 1,273 -
2025 1,275 1,275 -
2026 1,282 1,282 -
2027 1,289 1,289 -
2028 1,306 1,310 4
2029 1,313 1,325 12
41 2030 1,346 1,366 20
2031 1,357 1,388 31
2032 1,376 1,418 43
2033 1,375 1,429 54
2034 1,379 1,505 126
2035 1,378 1,576 198
The high electrification scenario changes load profi les and shifts peak load t o later in the evening, primarily due to expected increases in electric vehicle charging. This shift in load profi les explains why the volumetric energy (MWh) forecast is impacted by a great er percentage t han the coincident peak demand (MW) forecast. In 2035, for example, MCE projected annual retail sales are 14% higher under t he high electrification scenario, while coincident peak demand is only 6% higher.

In order to maintain GHG emissions below t he assigned limits, M CE would expect to increase it s proportionate use of renewable and other low GHG emitting resources. Whi le MCE can not specify t he exact resources or resource type it would utilize, t his would most likely come from additional out-of-st ate and/ or offshore resources. MCE does not have sufficient informat ion at this t ime to specify Transmission Zone and Substation/ Bus locat ions for t hese hypothet ical resource additions; however, a hypothetical example of a generic wind resource is provided in the t able below.

Table 10: MCE's Planned Out-of-State and Off-Shore Wind Resources Resource Annual 2035 Transmission Substation/ Alternative MWs GHG Note Type GWh target Zone Bus Location
Wyoming/ See subsections I.

Wind 250 900 0.504 TBD Morro Bay and m. for
Idaho
discussion
!1. Existing Resource Planning
Since MCE's launch in 2010, MCE has been committed to building and expanding access to in-stat e renewable generat ion resources. This is reflected by approximat ely 700 MWs of new build 42 43
renewable generation MCE has added to the grid and the additional approximately 500 MW37 of new build that MCE currently has under contract and that will be coming online by mid-decade. Further, as demonstrated in MCE’s PCP, which covers the full planning horizon, MCE will continue to drive significant new resource development, which will have a corresponding decrease in MCE’s planned use of existing resources.

As compared to MCE’s 2020 IRP, planned reliance on existing resources in 2030 has declined from 754 MW to 503 MW. Under MCE’s PCP, existing resources are planned to make up less than half of MCE’s total portfolio NQC in 2035. These existing resources include renewable resources that are already online and under contract, expected allocations of CAM resources from the PG&E portfolio, and expected resource adequacy contracts with existing generators.

Particularly during this energy transition and the need for renewables integration, it is reasonable and necessary to assume continued use of existing resources in light of studies indicating the importance of retaining existing resources to ensure grid reliability. The 2021 PSP, for example, shows retention of much of the existing natural gas fleet. MCE’s planned reduction in use of existing resources from 100% today to less than 50% in 2035, however, accommodates planned generator retirements and provides a reasonable transition away from fossil fueled capacity toward storage and other non-GHG-emitting technologies. MCE utilizes various procurement strategies to ensure access to resources in the market, including multi-year forward contracting with new and existing resources. i. Hydro Generation Risk Management
In developing its PCP, MCE took the following three key steps to manage the risk of reduced hydro-electric availability due to in-state drought:
● First, MCE reduced its overall reliance on large hydro-electric generation by adopting ambitious 2035 targets for renewable energy (which excludes large hydro-electric).

More specifically, MCE’s PCP in 2035 consists of 87% eligible renewable generation, which will limit its large hydro-electric procurement to 13% or less. This compares to MCE’s current use of large hydro for up to 40% of its electricity supply. MCE’s 87% renewable energy target significantly exceeds its current 60% level, and it also exceeds the 85% target that MCE submitted to the Commission in its 2021 Compliance IRP. ● Second, to the extent hydro-electric fits into the portfolio, MCE has an established network of Pacific Northwest hydro suppliers, including entities that have substantial 37 This number does not include incremental Shed Demand Response that MCE recently secured under contract (i.e., 15 MW of September NQC that is eligible incremental capacity under D.19-11-016). 44 ACS energy volumes. As a result of these substantial ACS volumes, suppliers are able to sell MCE reliable, firm volumes.
● Third, MCE has the ability to take deliveries of hydropower outside of the CAISO and schedule/import such volumes into the CAISO on its own, as a purchasing-selling entity registered with the North American Electric Reliability Corporation (“NERC”)-affiliated North American Energy Standards Board (“NAESB”). This substantially increases MCE’s flexibility as a counterparty and therefore provides MCE increased access to greater volumes of non-California hydro-electric resources from suppliers that may not be willing, themselves, to be the importer of record.

To the extent that hydro supply is unavailable, MCE would plan to use other sources of low carbon or carbon-free energy, which may include additional qualifying renewable energy.

Considering the relatively small volume of planned large hydro, the cost impacts of supply unavailability is limited. At the extreme, if MCE needed to replace its entire planned large hydro-electric energy with a renewable energy source such as wind, the cost impact to the portfolio is estimated to be less than 10%. A more realistic drought scenario would have cost impacts in the range of 0% to 5%. Moreover, the PSP’s hydro-electric energy resources are planned as energy-only. As such, there would be no direct reliability impacts to MCE’s PSP in the event of drought, although there may be system-wide reliability impacts to the extent that other LSEs utilize large hydro-electric resources for capacity purposes.

One technique MCE uses to manage variable hydro conditions is to include planned margins of over procurement in its hydro-electric purchasing strategy. These reserve margins apply to forward procurement and are gradually released as better information about hydro-electric availability becomes known.
j. Long-Duration Storage Planning
MCE is planning significant new battery storage capacity to help balance load and supply as it integrates a greater percentage of renewable energy into its supply mix and continues to reduce reliance on natural gas generation capacity. MCE sees a greater need and role for long-duration storage as the grid continues to evolve. To address this need, MCE is procuring to meet its long-duration storage requirement under D.21-06-035 (i.e., 29 MW of NQC) and anticipates procuring an additional 50 MW NQC of long-duration storage resources in the 2030 to 2035 timeframe.

In MCE’s view, battery storage technology is currently the most commercially viable technology to qualify for this long-duration attribute. However, MCE is also evaluating other technologies that have long-duration storage capability as well. Technology performance risk is the biggest 45 unknown at present because, with the exception of pumped hydro storage, there is no track record for utility scale, long-duration storage. MCE expects rapid technological improvement in battery storage as the industry continues to scale-up and anticipates declining costs in the longer-term. In the short-term, however, costs are increasing, and project opportunities are limited, particularly when the procurement is on accelerated procurement timelines. These factors may impact the pace at which MCE adds storage to its resource portfolio. k. Clean Firm Power Planning
MCE has prioritized acquisition of clean firm resources beyond what is required under existing Commission procurement orders. Despite higher costs, clean firm resources provide reliable capacity and a higher-value energy delivery profile as compared to solar and other intermittent resources. MCE is planning for greater use of geothermal resources over time due to its low carbon emissions and high resource value. Unfortunately, supply of geothermal, and clean firm resources generally, is very limited in California, and the cost of new-build resources is significantly higher. Clean firm energy imported from other balancing areas is complicated by transmission availability and the need to obtain equivalent Maximum Import Capability (“MIC”) through the CAISO in order to utilize the capacity under the resource adequacy program.

Despite these challenges to their expanded use, clean firm resources are important contributors to reliability and offer operational attributes that cannot be replicated by current-technology storage or other resource types. To develop these resources cost-effectively and efficiently, California LSEs will need the commitment of regulatory agencies and CAISO to facilitate this resource development by ensuring regulatory procedures and requirements align with market realities and that the transmission infrastructure necessary for this development is available and accessible to California LSEs.
l. Out-of-State Wind Planning
MCE’s PCP includes 70 MW of new, out-of-state wind, assumed to be located in New Mexico, with deliveries commencing in 2030. The choice of New Mexico wind is not intended to reflect a definitive plan for procurement from this area, and other locations for future wind projects are possible. New Mexico was selected as a likely source based on MCE’s review of wind projects that have been offered in recent solicitations. These opportunities utilize existing firm transmission routes into the CAISO. However, MCE observes the significant potential in the PSP for wind located in Wyoming and Idaho, as well as transmission projects being planned that would allow for delivery of this resource to California, which would indicate opportunities to contract for new wind from these areas should be prevalent in the 2030 timeframe provided the planning and construction of the Southwest Intertie Project-North (“SWIP-North”) transmission line proceeds expeditiously. Absent certainty that the SWIP-North transmission 46 line will be available with the appropriate level of import allocations and deliverability assurances for California LSEs, it will be difficult, or impossible to invest in this region’s renewable generation potential.
m. Offshore Wind Planning
MCE’s PCP includes 95 MW of offshore wind, assumed to be located at Morro Bay, with deliveries commencing in 2033. MCE has not yet seen any proposed opportunities to contract for offshore wind and is basing its planning assumption on the significant potential indicated in the PSP. Offshore wind appears to be a high potential resource with relatively high-capacity factors and resource adequacy values. At this time, costs of offshore wind development and maintenance infrastructure are largely unknown. As such, cost and development timelines pose the greatest risk to utilization of this resource. Despite these near-and possible near-term barriers to progress on this front, MCE is monitoring the issue as it evolves, and procurement of offshore wind becomes feasible.
n. Transmission Planning
i. New Projects
This section describes new generation projects that are under development and planned projects that have been specifically identified through MCE’s procurement processes where there is sufficient locational specificity that could be useful to the transmission planning process.
ii. Projects Under Development
Strauss Wind, LLC
This is a new-build wind project. The expected commercial operation date (“COD”) is in 2023, and MCE intends to apply this resource towards its procurement requirements under D.19-11-016. The project is located in Santa Barbara County.

The interconnection queue position is WDT-1320. All transmission upgrades needed for this project have been completed. The Strauss Wind project is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. Please refer to row 41 of the unique_contracts tab in MCE’s RDTs.

Golden Fields Solar IV, LLC
-
47 This is a new-build hybrid project located in Kern County that pairs 100 MW of solar with 92 MW four-hour battery storage. The project has an expected COD of March 2025 and is intended to apply towards MCE’s mid-term reliability (“MTR”) requirements under D.21-06-035. The interconnection queue position for this resource is Q-1211, and the project will connect at the Southern California Edison (“SCE”) Whirlwind 230 kV substation. Transmission upgrades needed for this project are expected to be completed in October 2024. These transmission upgrades are described in Appendix A to the Large Generator Interconnection Agreement (“LGIA”) and include participating transmission owner (i.e., SCE) reliability network upgrades.

The Golden Fields Solar project is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. Please refer to row 51 of the unique_ contracts tab in MCE’s RDTs.

Daggett Solar Power 3, LLC
This is a new-build hybrid project located in San Bernardino County that pairs 110 MW of solar with 60 MW of four-hour battery. The project has an expected COD of August 2023, and MCE intends to apply this capacity towards its MTR requirements under D.21-06-035. The interconnection queue position is Q-1314, and the project will connect at Kramer Substation 220kV switchrack. Transmission upgrades needed for this project are expected to be completed in December 2022. These transmission upgrades are described in Appendix A to the LGIA and include participating transmission owner (i.e., SCE) reliability network upgrades. The Daggett Solar Power project is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. Please refer to row 55 of the unique_ contracts tab in MCE’s RDTs.

Hecate Grid Humidor Storage 185, LLC
This new 185 MW four-hour battery storage project has an expected COD of April 2024 and will be located in Los Angeles County. MCE intends to apply this capacity towards its MTR requirements under D.21-06-035. The interconnection queue position is Q-1629, and the project will connect at SCE Vincent Substation, 220kV Bus. Transmission upgrades needed for this project are expected to be completed in Q4 2023. These transmission upgrades include extending the existing 230kV bay within the substation and installing an intermediate structure to connect to the Point of Interconnection (“POI”) riser outside of the substation. The Hecate Grid Humidor Storage project is represented in both the 30MMT and 25MMT RDTs, 48 respectively, as incremental capacity. Please refer to row 64 of the unique_ contracts tab in MCE’s RDTs.

RPCA Solar 3 - Byron Highway Solar
This is a new-build 5 MW solar project located in Contra Costa County. The project has an expected COD of November 2022. The interconnection queue position is 2296-WD, and the project will connect at Brentwood distribution substation. All transmission upgrades needed for this project have been completed. The RPCA Solar 3-Byron Highway Solar project is represented in both the 30MMT and 25MMT RDTs, respectively. Please refer to row 40 of the unique_contracts tab in MCE’s RDTs.

Ranch Sereno Clean Power, LLC
This is a new build 2MW solar project with 0.8 MW of four-hour battery storage. The project is located in Contra Costa County and has an expected COD of February 2024. The interconnection queue position is 2597-WD, and the project will connect at PG&E’s Brentwood distribution substation. No transmission upgrades are required for this project. The Ranch Sereno Clean Power project is represented in both the 30MMT and 25MMT RDTs, respectively. Please refer to row 52 of the unique_contracts tab in MCE’s RDTs.

CES Electron One Farm, LLC
This new-build project consists of two solar projects sized at 4.4 MW and 0.24 MW.

The projects are located within specified Disadvantaged Community areas in Fresno County and have an expected COD of December 2023. The interconnection queue position is 2226-WD, and the project will connect at PG&E’s Panoche distribution substation. No transmission upgrades are required for this project. The CES Electron One Farm project is represented in both the 30MMT and 25MMT RDTs, respectively.

Please refer to rows 53 and 54 of the unique_contracts tab in MCE’s RDTs. iii. Projects Under Review
49 iv. Planned New (Generic) Projects
The following projects included in the PCP are generic in nature. Locations and technology resource types are subject to change as MCE advances in its procurement.

OS22 New Wind 2026
This generic 100 MW wind project with initial deliveries commencing in 2026 is assumed to be located in the Tehachapi area.

Generic LT Wind NM 2030
This generic 70 MW wind project with initial deliveries commencing in 2030 is assumed to be located in New Mexico. Please see subsections iv. and v., below, for additional details on planning assumptions for this project.

Generic LT Wind 2033
This generic 95 MW wind project with initial deliveries commencing in 2033 is assumed to be located offshore of Morro Bay. Please see subsections iv and v, below, for additional details on planning assumptions for this project.

Generic LT Geothermal 2030
This generic 75 MW geothermal project with initial deliveries commencing in 2030 is assumed to be located in the Imperial Valley.

MTR LDS 2026
This generic eight-hour battery storage project with initial operation commencing in 2026 is assumed to be located in Contra Costa.
50 Generic LDS 2030
This generic eight-hour battery storage project with initial operation commencing in 2030 is assumed to be located in Contra Costa County.

Generic 4 Hour Storage 2028
This generic four-hour battery storage project with initial operation commencing in 2028 is assumed to be located in Solano County.

Generic 4 Hour Storage 2034
This generic four-hour battery storage project with initial operation commencing in 2034 is assumed to be located in Napa County.

IV. Action Plan
a. Proposed Procurement Activities and Potential Barriers To achieve its PCP over the planning horizon, MCE plans to steadily procure volumes at regular intervals to allow MCE to keep within its established position limits and avoid concentrated procurement during any particular market environment. This is consistent with MCE’s risk management approach to spread out the potential cost risks that may be at play in the market at any given year, while maximizing the potential for MCE to optimally procure. At a high level, MCE plans to procure renewables and storage, large hydro-electric and ACS, RA (including incremental capacity required by the Commission) and load-hedging products.

MCE’s goal is to procure such products in a manner that is cost effective, achieves emissions and reliability objectives, and supports a well-balanced and optimal resource portfolio.

To support this goal, MCE also considers the following strategies:

Joint Solicitations
Joint solicitations can expand the procurement opportunities available to a CCA, as well as provide procedural efficiencies, economies of scale, and overall cost savings for participating organizations. MCE is closely networked with other CCAs through its membership in the California Community Choice Association (“CalCCA”), the trade organization representing California’s CCA sector, and regularly coordinates with other CCAs regarding prospective 51 procurement opportunities and portfolio balancing activities.

Optimizing Existing Procurement
As MCE considers its long-term resource needs, it will evaluate options in its future PPAs to increase output through either facility upgrades or adding new capacity to the generating facility. Expanding existing facilities may provide additional generation at reduced costs with a lower risk of project failure because the need for distribution system upgrades and permitting may be reduced. However, MCE has experienced some challenges as it pertains to transmission upgrades and deliverability of new capacity on to the grid. MCE continues to engage with relevant stakeholders and developers to evaluate the feasibility of such expansions for implementation.

Annual Energy Solicitations
In addition to periodic joint solicitations, MCE will also run targeted solicitations in the upcoming years to further optimize its current portfolio needs. Such solicitations may provide MCE with flexibility and potential to meet specific portfolio needs and obligations unique to MCE.

MCE also considers the deliverability characteristics of its resources (including the expected delivery profile, available capacity and dispatchability attributes, if any, associated with each of its generating resource and/or supply agreements) and reviews the respective risks associated with short- and long-term purchases as part of its forecasting and procurement processes.

These risk evaluations include, but are not limited to, transmission availability, MIC allocation, and exposure to global supply and market forces.

These efforts lead to a more diverse resource mix, help to address grid integration issues, improve the probability of project delivery, and provide value to MCE’s member communities through reduced costs and support in achieving planned procurement objectives.

MCE has a well-established procurement process that it will use to steadily achieve its PCP over the next twelve years (i.e., by 2035). This process is used by MCE in executing all its planned new resources. MCE’s procurement process includes the following ten key activities:

1. Load forecasting based on the number and types of customers, potential service territory expansions, opt-out rates, electrification trends, demand-side resources and weather;

2. Integrated resource planning based on load forecasts, renewables and emissions targets, agency-wide budgetary considerations and customer rate implications, 52 long- term contracting requirements and goals for new steel in the ground, grid reliability needs and capacity requirements, market price hedging needs and goals for local resources, local resiliency and local workforce development;

3. Calculating open positions and interim volumetric needs based on MCE’s risk management policies;

4. Soliciting volumetric needs through RFOs, bilateral discussions or brokers;

5. Evaluating offers using a combination of proprietary and public models;

6. Negotiating (and ultimately executing) power purchase agreements, enabling agreements and confirms – including credit provisions and collateral requirements;

7. Managing pre-COD executed contracts and monitoring progress towards key development milestones (such as interconnection status, deliverability studies, siting, zoning, permitting, financing, construction, commercial operation, etc.)

8. Managing post-COD executed contracts: obtaining generation forecasts, bidding/scheduling resources into the CAISO markets, validating and paying invoices, etc.;

9. Bidding/scheduling MCE’s load into the CAISO markets; and

10. Regulatory compliance reporting.

With respect to activity number four listed directly above, MCE plans to conduct an annual “open season” RFO in the first half of each year for new renewable generation and storage projects. MCE anticipates that the majority of its open seasons over the next several years will result in executed long-term PPAs for new renewables and/or storage, and MCE anticipates that such projects will achieve commercial operation within 3 years of contract execution. In these solicitations for long-term renewable energy and storage, MCE imposes numerous bid requirements on interested respondents. These requirements address a variety of considerations and are intended to identify the best qualified suppliers of MCE’s long-term renewable energy needs. Such requirements include:

1. Overall quality of response, inclusive of completeness, timeliness, and conformity;

2. Price and relative value within MCE’s supply portfolio;

3. Project location and local benefits, including local hiring and prevailing wage considerations;

4. Project development status, including but not limited to progress toward interconnection, deliverability, siting, zoning, permitting, and financing requirements;

5. Qualifications, experience, financial stability, and structure of the prospective project team (including its ownership);

6. Environmental impacts and related mitigation requirements, including impacts to air pollution within communities that have been disproportionately impacted by the ■
53 existing generating fleet;

7. Potential impacts to grid reliability;

8. Acceptance of MCE’s standard contract terms; and

9. Development milestone schedule, if applicable.

In addition, MCE is planning to solicit offers periodically throughout each year for short term renewable energy, large hydro-electric and ACS, resource adequacy and load-hedging products needed to balance the portfolio and adhere to position limits established through MCE’s risk management policy and practices.

MCE uses a portfolio risk management approach in its power purchasing program, seeking low-cost supply, based on then-current market conditions, as well as diversity among technologies, production profiles, project sizes and locations, counterparties, lengths of contract, and timing of market purchases.

A key component of this process relates to the analysis and consideration of MCE’s forward load obligations and existing supply commitments with the objectives of closely balancing supply and demand, cost/rate stability and overall budgetary impacts, while leaving some flexibility to take advantage of market opportunities and technological improvements that may arise over time. MCE monitors its open positions separately for each renewable generating technology, GHG-free resources, conventional resources, and its aggregate supply portfolio.

MCE maintains portfolio coverage targets of up to 100% of expected customer energy requirements in the near-term (0 to 2 years). Typically, MCE has gradually larger open positions in the mid- to long-term, consistent with generally accepted industry practices.

In addition to the planned and proposed procurement activities, MCE also takes into consideration the various barriers that may impact the success of its planned renewable projects. Some of the potential barriers for each of the new resources identified in MCE’s PCP include:

1. New Wind: The current market conditions have made new in-state wind resources scarce, which has led to a price premium and escalated cost risks on any available in-state wind resources. In addition, the transmission constraints and limited MIC allocation for out of state wind has made it difficult to negotiate and plan for new resources due to the uncertainty of deliverability.

2. New Geothermal: Due to the scarcity of new geothermal projects in-state and the uncertainty of deliverability and transmission of out of state geothermal projects, there has been an unprecedented competition on available geothermal, causing an ever-increasing upwards pressure in price. If this trend continues it may impact MCE’s ability ■
54 to procure new geothermal resources in the near-term.

3. Hybrid Resources: Currently, most hybrid resources primarily consist of intermittent resources like solar. As solar is highly affected by global supply chain issues, most planned projects are facing upward pressures in cost and are consequently facing further delays.

4. Storage: Similarly, to hybrid resources, global supply chain issues and the scarcity of the raw materials required for battery production, there is risk and uncertainty in prices and expected delivery dates that may negatively impact MCE’s planned portfolio and budgeted costs.

MCE continuously monitors the developments in the market and engages with various market stakeholders including the Commission, CAISO, and other CCAs, to strategize and find solutions to the various barriers and the risks associated with new clean energy procurement.

Throughout the planning period MCE will continue to proactively evaluate its planned procurement and make necessary adjustments to meet its portfolio needs as determined by MCE’s Board and its operational and compliance needs.
i. Resources to meet D.19-11-016 procurement requirements In D.19-11-016, the Commission ordered LSEs to collectively procure a total of 3,300 MW of incremental system capacity by 2023, with specific procurement obligations allocated to each LSE. As part of MCE’s contribution to system reliability and renewable integration needs, MCE is committed to self-providing its share of the identified system capacity need.38 MCE’s assigned share is 87.5 MW,39 50% of which was online by August 1, 2021, 75% of which was online by August 1, 2022, and 100% of which is expected to be online by August 1, 2023.

D.19-11-016 Procurement Progress Report
MCE has executed agreements that will satisfy MCE’s 2021, 2022 and 2023 incremental capacity requirements under D.19-11-016. As of the date of this filing, MCE has 108.77 MW40 of 38 Marin Clean Energy’s February 15, 2020, Integrated Procurement Planning Progress Report Pursuant to Decision 19-11-016 Adopted in Rulemaking 16-02-007 filed February 18, 2020. 39D.19-11-016 at Ordering Paragraph 3.
40 For consistency purposes, MCE is calculating September NQC based on the most recent ELCC factors adopted in D.22-08-039 and the September NQC assigned to MCE’s resources in the RDTs. However, using the more conservative NQC values, MCE has 101.9 MW of NQC either online or under contract to meet its D.19-11-016 requirement. This capacity includes a recently executed agreement for incremental capacity. However, due to the Commission’s August 1, 2022, cutoff for contracts, MCE includes this contact in its RDTs as a resource under review (see unique_contracts tab of the RDT Row 115) but includes this capacity in this progress report to provide the Commission the most up-to-date information on its D.19-11-016 procurement. MCE will reflect this resource as in 55 September NQC under contract; this is NQC not included on the baseline resource list adopted in Rulemaking 16-02-00741 and exceeds MCE’s 87.5 MW incremental capacity requirement. The projects reflected in these contracts are either already online or expected to be online in advance of August 1, 2023.

MCE also provides a narrative description of specific incremental procurement efforts below, which is consistent with the information MCE provides the CPUC in its bi-annual D.19-11-016 compliance filings.

Sutter Energy Center
The Sutter Energy Center project has been online since January 1, 2021 under a 3-year Purchase & Sale Agreement between MCE and Calpine Energy Services, L.P.. The period for this agreement began on January 1, 2021 and will continue through December 31, 2023, which is consistent with D.19-11-016’s requirement that commitments based on existing resources must “stay in place at least through the end of the resource adequacy summer months of 2023.”42 Additionally, D.19-11-016 defines the Sutter Energy Center as an incremental capacity resource.43 Although physically located outside of the CAISO balancing authority, D.19-11-016 also indicates that Sutter Energy Center is not an import for purposes of the capacity procurement ordered by the decision and thus not subject to the D.19-11-016’s 20% limitation on import resources.44
Sutter Energy Center adds 69.55 MW of incremental capacity to the system from January 2021 through 2023. As such, this project satisfied both MCE’s 2021 and 2022 requirements.

The Sutter Energy Center is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. For this resource, please refer to row 59 of the unique_contracts tab in MCE’s RDTs.

Strauss Wind, LCC
In 2018 MCE executed an Amended and Restated Renewable Power Purchase Agreement with Development in its next D.19-11-016 RDT compliance filing. Under either NQC methodology, MCE has more than its share of incremental capacity under contract for purposes of D.19-11-016. 41 See Administrative Law Judge’s Ruling Finalizing Baseline for Purposes of Procurement Required by Decision 19-11-016 filed January 3, 2020, Rulemaking 16-02-007. 42D.19-11-016 at 47.
43D.19-11-016 at Ordering Paragraph 6.
44 Id.

Strauss Wind, LLC, a California Limited Liability Company ("Strauss Wind project"). This 20-year PPA is for a new-build wind energy proj ect located in Santa Barbara County, California. is a new grid resource that is not included on the baseline resource list adopted in Ru lemaking 16-02-007. Thus, the Strauss Wind project is eligible to count towards MCE's assigned 87.5 MW of incremental system resource capacity.

The project began construct ion in March 2020.

The Strauss Wind project is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. For this resource, please refer to row 41 of the unique_contracts tab in MCE's RDTs.

MCE Solar One
MCE's Solar One proj ect is currently on line and has been delivering energy since December 22, 2017, under a 20-year PPA with MCE. MCE Solar One is a 10.5 MW solar faci lity located in Richmond, California. Using the current NQC framework, this resource provides an additional

1.16 MW of September NQC that is not reflected on the baseline resource list. As such, MCE Solar One applies towards MCE's incremental system capacity procurement compliance requirement.

The MCE Solar One project is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. For this resource, please refer to rows 35 and 36 of the unique_contracts tab in MCE's RDTs.

Waste Management Redwood Landfill ("Redwood Landfill Project") The Redwood Landfi ll project is currently online and has been delivering energy since September 14, 2017, under a 20-year PPA with MCE. The Redwood Landfi ll proj ect is a 3.9 MW landfi ll gas-fired generation facility located in Novato, California. This resource provides an 45 See MCE's August 1, 2022, D.19-11-016 Compliance Filing for additional detail provided in the Remediation Plan. 56 additional 3.39MW of September NQC under the current framework and according to the September NQC assigned in the RDTs. This is incremental capacity that is not reflected on the baseline resource list. As such, the Redwood Landfi ll project applies towards MCE's incremental system capacity procurement compliance requirement.

The Redwood Landfi ll project is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. For this resource, please refer to row 7 of the unique _contracts tab in MCE's RDTs.
i. Resources t o meet D.21-06-035 procurement requirement s, including:
a. 1,000 MW of firm zero-emitting resource requirement s b. 1,000 MW of long-duration storage resource requirements c. 2,500 MW of zero-emissions generation, generation paired with storage, or demand response resource requirements
In D.21-06-035, the Commission ordered LSEs to collectively procure a total of 11,500 MW of incremental system capacity by 2026, with specific procurement obligations allocated to each LSE to support mid-term system reliabi lity needs. MCE's assigned share of this procurement is 332 MW of NQC,47 58 MW of which must be onl ine by August 1, 2023, an additional 173 MW of which must be on line by June 1, 2024, an additional 43 MW of which must be on line by June 1, 2025, and an additional 58 MW of which must be on line by June 1, 2026.

MTR Procurement Progress Report
MCE has executed agreements that MCE expects will satisfy its 2023, 2024 and 2025 incremental capacity requirements. As of the date of this fi ling, MCE has 308.7 MW of eligible NQC under contract towards its D.21-06-035 requirement, which represents 395 MWs of nameplate capacity.

MCE' s completed procurement towards its D.21-06-035 requirement is reflected in MCE' s 25 MMT and 30 MMT RDTs, respectively. MCE also provides a narrative description of specific incremental procurement efforts below.

Firm Zero-Emitting Resources {MCE Requirement= 29 MW of NQC) I
47 D.21-06-035 at 56.
57 58
Long-Duration Storage (MCE Requirement = 29 MW of NQC)

Zero Emissions Generation (MCE Requirement = 274 MW of NQC) ● Golden Fields Solar IV
MCE executed a contract with Clearway Energy Group on February 4, 2022, for a new-build hybrid project located in Kern County that pairs 100 MW of solar PV with 92 MW four-hour battery storage. This project has an expected COD of March 2025, and MCE expects to apply this resource to count for at least 75 MW of NQC towards its general MTR requirements under D.21-06-035, including towards MCE’s 72 MW of zero-emitting resources pursuant to Table 6 in D.21-06-035.48 The Golden Fields Solar project is represented in both the 30 MMT and 25 MMT RDTs, respectively, as incremental capacity. Please refer to row 51 of the unique_contracts tab in MCE’s RDTs. ● Daggett Solar Power 3, LLC
MCE executed a contract with Clearway Energy Group on September 25, 2020, for a new-build hybrid project in San Bernardino County that pairs 110 MW of solar PV with 60 MW four-hour battery storage. This project has an expected COD of August 2023, and MCE expects to apply this resource to count for at least 65.9 MW of NQC towards its MTR requirements under D.21-06-035, which also contributes towards MCE’s 72 MW 48 MCE expects this resource to provide at least 61.3 MW of DCPP replacement capacity. To apply towards both the general MTR requirements and MCE’s requirement to procure 72 MW of zero-emitting resources with certain availability requirements, MCE’s PPA for this project ensures that this hybrid resource will be designed to be capable of delivering 5 MWh of energy per every MW of claimed incremental capacity during the 5PM to 10PM period, daily.

I
59 of zero-emitting resources pursuant to Table 6 in D.21-06-035.49 The Daggett Solar Power project is represented in both the 30MMT and 25MMT RDTs, respectively, as incremental capacity. Please refer to row 55 of the unique_contracts tab in MCE’s RDTs. ● Hecate Grid Humidor Storage
MCE executed a contract with Hecate Grid in August 2022 for a new 185 MW four-hour battery storage project in Los Angeles County. This project has an expected COD of April 2023, and MCE expects to apply this resource to count for at least 167.8 MW of NQC towards its MTR requirements under D.21-06-035. The Hecate Grid Humidor Storage project is represented in both the 30 MMT and 25 MMT RDTs, respectively, as incremental capacity. Please refer to row 64 of the unique_contracts tab in MCE’s RDTs. i. All other procurement requirements
Open Season RFO
After counting the above-mentioned resources
To fill any current and future open positions, MCE issues annual open season RFOs, which seek to fill approximately 350 GWh of annual energy needs, including any incremental procurement that might be needed to meet D.21-06-035. These RFOs request offers for Portfolio Content Category 1 Renewable Energy and stand-alone, front-of-the-meter energy storage. MCE is in the final stages of completing power purchase agreements with selected respondents from 2021 RFO and expects to procure significant volumes of hybrid resources, all of which will be agreements of at least 10 years in duration. In addition, MCE expects to count these 2021 and future RFOs projects towards any future Commission-directed incremental capacity obligations. While MCE does not anticipate that the new projects will be needed for MCE’s share of capacity requirements identified in D.21-06-035, they may provide back up to the projects identified above.

Because these resources are expected/planned, and not currently contracted for, these resources are reflected as “review,” “PlannedExisting,” and “PlannedNew”resources in both the 30 MMT and 25 MMT Resource Data Templates.
49 MCE expects this resource to provide at least 48 MW of DCPP replacement capacity. To apply towards both the general MTR requirements and MCE’s requirement to procure 72 MW of zero-emitting resources with certain availability requirements, this hybrid resource is capable of delivering 5 MWh of energy per every MW of claimed incremental capacity during the 5PM to 10PM period, daily. 60 ii. Offshore wind
MCEs PCP includes 95 MW of offshore wind, assumed to be located at Morro Bay, with deliveries commencing in 2033. MCE has not yet seen any proposed opportunities to contract for offshore wind and is basing its planning assumption on the significant potential indicated in the PSP. Offshore wind appears to be a high potential resource with relatively high-capacity factors and resource adequacy values. At this time, costs of offshore wind development are largely uncertain. As such, costs of offshore wind development and maintenance infrastructure pose the greatest risk to utilization of this resource. However, the completion of environmental impact review and filing a proposed sale notice for the Humboldt Wind Energy Area by the federal Bureau of Ocean Energy Management (“BOEM”) is an important initial step. MCE will continue to monitor the developments and will engage the various stakeholders involved, should an opportunity to purchase offshore wind arise.
iii. Out-of-state wind
MCE’s PCP includes 70 MW of planned new, out-of-state wind (“OOS”), with deliveries commencing in 2030. MCE has reviewed wind projects that have been offered in recent solicitations and understands that the transmission projects needed to connect OOS Wind to the CAISO grid require significant lead-times. OOS wind opportunities rely on existing firm transmission routes into the CAISO or construction of new transmission with the appropriate level of import allocations and deliverability assurances for California LSEs. Absence of such assurances make it difficult for MCE to realize the significant potential for wind located in Idaho, Wyoming, and New Mexico. Given the fact that OOS Wind is not needed until 2030, MCE believes that a careful and considered approach to potential OOS Wind projects is best. MCE will continue to monitor for opportunities to purchase such resources and will evaluate offers it receives during its annual open season process.
iv. Other renewable energy not described above

v. Other energy storage not described above
MCE is not actively planning for any additional energy storage investments beyond what is described above.
61 vi. Other demand response not described above
In April 2021, MCE launched the Peak FLEXmarket, a first-of-its-kind program platform aimed at shifting energy use in its service area away from times of extreme demand. Following its initial pilot year, the program received $11 million in ratepayer funding from the CPUC for the summers of 2022 and 2023. Created in partnership with Recurve, the Peak FLEXmarket provides tools to measure hourly reductions in energy use that allows MCE to compensate businesses working locally with customers for energy savings during peak demand hours. The program is technology agnostic and incentivizes load reductions from a diverse group of technologies including batteries, managed EV charging, controls systems and behavioral/operational change. The Peak FLEXmarket incentivizes regular load shifting and also calls demand response events during periods of extreme grid stress. The Peak FLEXmarket has been included in MCE’s Energy Efficiency Business Plan Application for continued funding for the 2024-2027 timeframe.

MCE plans to expand this program to monitor and control other customer owned DERs.

In addition to the City of Richmond VPP described above, MCE continues to explore opportunities for demand response in its service area while facilitating third-party demand response programs. MCE customers are eligible for many of the demand response programs administered by PG&E, and MCE receives allocations from PG&E-administered programs.

Depending on the results of this analysis, MCE may launch new programs and possibly seek funding from other sources for more robust programs in this sector. vii. Other energy efficiency not described above
MCE is an administrator of California’s ratepayer-funded, energy efficiency programs alongside IOUs and Regional Energy Networks. Ratepayer funding is derived through collection of the Public Purpose Program charge from all electric service customers and is administered by the Commission. MCE has received Commission funding approval for energy efficiency programs to be administered through 2025 and currently administers programs in multifamily, single family, commercial, agriculture, and industrial sectors. Furthermore, MCE administers the Low-Income Families and Tenants (“LIFT”) Program, which serves income-qualified, multifamily properties and includes a fuel-switching component to incentivize property owners to replace gas-fired space and water heaters. The forecasted cumulative savings of MCE-administered energy efficiency programs are based on average life cycle savings. ■
62 MCE also invests in multiple workforce development initiatives to encourage the growth of green jobs through the approval of its Energy Efficiency Business Plan. MCE also coordinates closely with PG&E to maximize community benefits.

MCE cumulative energy efficiency impacts (GWh)
viii.Other distributed generation not described above
Net Energy Metering and Rooftop Solar Rebates
Through its Net Energy Metering (“NEM”) program, MCE supports customer-sited distributed generation within its service area by offering above-market incentives including automatic cash-outs for surplus generation each year at twice the wholesale rate (up to $5,000). MCE’s NEM Program currently includes more than 63,528 customers (10.9% of all MCE accounts) with an aggregate-installed renewable generating capacity of approximately 642 MW.

Through 2021, MCE incentivized local rooftop solar development for low-income customers.

MCE has a long-standing partnership with California’s Single Family Affordable Solar Housing (“SASH”) program administrator, GRID Alternatives. By leveraging multiple sources of funding, GRID Alternatives installs these systems in disadvantaged communities at little to no cost for the customer. MCE contributed $900 per solar installation to qualifying low-income, single-family homeowners. MCE also offered a $0.41 per watt (AC) rebate to low-income, multifamily properties that install solar to benefit their tenants.

From 2012–2021, MCE allocated $725,000 toward these two rebate programs, and supported the installation of 688 residential solar PV systems on low-income multifamily homes. These 140
120
100
80 60
40 20
0 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Year
63 installations represent more than 1,400 kW of new, local, renewable capacity that helps reduce monthly energy bills for low-income families.
ix. Transportation electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR) As part of its broader strategy to reduce GHG emissions through buildings and transportation electrification, MCE has been working on several EV-related initiatives since 2017. These include demand response-enabled charging devices, equity-centered incentives for EVs, and funding for charging stations. These efforts started with a strategic plan and infrastructure analysis in partnership with the U.S. Environmental Protection Agency to analyze local EV market trends and their impact on MCE’s customer demand.

MCE has identified workplace EV charging as an opportunity to shift the demand of the 60,200 (and growing) EV drivers in its service area to hours of the day when energy is frequently cheaper and cleaner. MCE Solar Charge, a public EV charging station that opened in 2019 at MCE’s San Rafael office, demonstrates that vision to MCE’s staff and customers. In 2021, MCE launched MCE Sync, a residential smart charging pilot with the goal of reducing the peak load impacts of home charging while saving customers money and reducing GHG impacts.

MCE Sync uses an app to manage home vehicle charging. During a 6-month pilot with 232 enrolled participants, the pilot shifted 93% of EV electricity usage away from the 4–9 p.m. peak, reduced carbon intensity by 55% on average, and saved customers on an EV rate around $12/month before event-based incentives. The expanded program has a goal of 2,500 enrolled customers by May 2023.

Since 2018, MCE has supported or funded 1,570 Level 2 EV charging ports for workplaces or multifamily properties. More than 930 ports have been installed — equivalent to 36% of all public Level 2 charging ports in the four counties that MCE serves — and more than 645 ports under planning and in construction. MCE is coordinating with PG&E on its EV Charge Network program and providing a supplemental rebate to customers who participate in that program.

More than 71% of the MCE stations already deployed are enrolled in MCE’s Deep Green service.

In addition to incentives for EV charging stations, MCE provides free technical assistance and helps coordinate with other funding sources for commercial and multifamily customers interested in EV charging infrastructure. A CEC grant won by Contra Costa Transportation Authority and MCE will increase EV engagement, access to electric transportation, and deployment of charging infrastructure, especially at multifamily properties, across marginalized communities in the county from summer 2021 to spring 2024. ■
64 MCE also partnered with Bay Area Air Quality Management District and GRID Alternatives to win grants from the CEC and Marin Community Foundation. These grants are anticipated to start in the second half of 2022. Implementation will focus on deepening relationships with local housing authorities, affordable housing administrators, owners, and property managers to increase awareness and adoption of tenant-based EV charging stations. The implementation consists of installing EV charging and providing concierge education on how to qualify for income-based EV incentives, including MCE’s own EV rebate.

Lastly, MCE built upon its rebate program for income-qualified customers interested in purchasing a new EV with the goal of increasing understanding of and access to EVs beyond the typical early adopters. This program has helped over 261 customers purchase or lease a new EV and will expand in fiscal year 2023/2024 to include used EVs as well. x. Building electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR)
MCE is committed to electrifying its service area and is currently offering several programs that it expects will impact building electrification efforts including its: LIFT Pilot Program, Multifamily Energy Savings (“MFES”) Program, Home energy Savings (“HES”) Program, and Heat Pump Water Heater (“HPWH”) Contractor Incentive Program. An overview of MCE’s planned investment in these programs is provided below.

Multifamily Energy Saving Program
MCE’s MFES provides residential energy efficiency50 and electrification51 improvements to affordable multifamily properties in the MCE service area. The intent of the program is to support vulnerable communities, particularly those who have been traditionally underserved.

MFES seeks to substantially fund energy efficiency and electrification measures for deed-restricted properties. It will also continue to co-leverage as many funding opportunities to provide comprehensive, whole building upgrades.

MFES was designed to co-leverage with MCE’s LIFT pilot program, authorized in D.16-11-022, by providing funding to affordable properties where not all units qualify for LIFT incentives. LIFT provides comprehensive services and supports fuel switching from natural gas to electric heat pumps for cleaner and safer energy use. Income-qualified multifamily properties can layer 50 Refrigerators, package terminal heat pumps, LED light fixtures, smart thermostats, low flows showerhead and aerators, and LED bulbs, T24 compliant windows, crawlspace, wall, and roof insulation. 51 Domestic hot water heat pump, space heating and cooling and electrical upgrades. 65 incentives from LIFT on MFES program rebates. With this model, MFES supports property-wide upgrades for all tenants who live in affordable housing.

MFES services include no-cost property assessments, project scope development, and program assistance throughout the project lifetime. The program also offers owner rebates for energy efficiency and electrification measures as well as no-cost direct installation of certain energy efficiency measures.

The program addresses market barriers by providing: (1) customized technical assistance to; overcome challenges associated with the diversity of building types, ownership types, and billing configurations, and to provide assistance with analyzing potential upgrade measures; (2) guidance through the initial assessment of multiple measure upgrade opportunities throughout the property; (3) a range of participation options to best meet the current needs and abilities of properties; and (4) a bridge for the funding gap between multifamily units that qualify for LIFT or ESA incentives and the rest of the property to promote a comprehensive and equitable whole-building upgrade.

The current budget for the MFES program is $1,017,476 for 2022 and $971,459 for 2023. The current timeline for the program is 2022-2024, with project renewal expected every two years.

LIFT Pilot Program
MCE launched the LIFT pilot in 2017, providing additional incentives for property owners and tenants in multifamily buildings (5+ units) beyond what is available through the MFES program.

LIFT provides $1,200 per unit for energy efficiency upgrades52 and additional incentives for fuel substitution and fuel switching away from natural gas and propane combustion appliances to high efficiency electric heat pumps53 (HVAC and water heating). This transition will support cleaner and more efficient energy use while resolving health and safety concerns.

MCE’s LIFT program aims to support income-eligible multifamily renters with improving their household efficiency, reducing their energy costs, and increasing home safety and comfort, while simultaneously maximizing benefits to owners. The program is part of a larger goal of California’s climate initiatives to support disadvantaged customers and increase statewide electrification and efficiency efforts. The literature review outlines the current regulatory 52 Refrigerators, package terminal heat pumps, LED light fixtures, smart thermostats, low flows showerhead and aerators, and LED bulbs, T24 compliant windows, crawlspace, wall, and roof insulation. 53 Domestic hot water heat pump, space heating and cooling and electrical upgrades. 66 context within California, discusses DAC definitions and metrics, electrification, health and safety, costs, and barriers to emerging technology adoption.

The LIFT pilot was originally approved by the CPUC to run under the Energy Savings Assistance (“ESA”) program, followed by a series of extensions granted to keep this running as a pilot through 2023. The LIFT Program distributed over $1 million in incentives to 680 qualifying households between 2018 and 2021 and successfully reached underserved customers with 95% of participants residing outside of a DAC. Participants collectively saved over 7,800 kilowatt-hours annually and, individually, an average of $192 per year on their electricity bill.

MCE expects to serve more than 450 additional households in the LIFT program through 2023.

MCE’s MFES and LIFT programs have different funding sources (CPUC – Energy Efficiency and CPUC – Energy Savings Assistance, respectively), which makes it possible for MF properties to leverage incentives from both programs. The two programs share the same implementor, providing a single point of contact (“SPOC”) and stack incentives for low-income multifamily customers. The rebates, when combined with MCE’s Multifamily Energy Savings program, cover up to 80% of total project costs. The program currently has a timeline of October 2017 – December 2023 with a budget of $6.75 million.

Home Energy Savings (“HES”) Program
MCE’s Single-Family Direct Install program, or Home Energy Savings Program (“HES”), provides no-cost energy efficiency measures to eligible homeowners and tenants in single-family homes (up to 4 attached units) and dwellings in MCE’s service area. This program targets moderate-income customers whose household income falls between 200% and 400% of the Federal Poverty Guidelines (“FPG”). The target group’s income exceeds the limit to receive services through programs like PG&E’s Energy Savings Assistance (“ESA”) program and MCE’s LIFT Program, yet who are still too income constrained (lower middle-income) to participate in market rate programs. MCE will refer customers who fall outside of the moderate-income threshold to available low-income and market rate programs. MCE’s goal is to fill the service gap and introduce this market sector to the concepts of energy efficiency, while providing energy upgrades and emerging technologies that reduce household energy consumption.

Energy efficiency measures offered under this program include: energy and water savings kits, energy advisor provided home assessments and envelope, heating, ventilation and cooling (HVAC) and electrification home upgrade measures.

The current budget for the HES program is $2,366,392 for 2022 and $2,384,874 for 2023. The current timeline for the program is 2022-2024, with project renewal every two years. 67 Heat Pump Water Heater (“HPWH”) Contractor Incentive Program BayREN has partnered with MCE, East Bay Community Energy, Silicon Valley Power, City of Santa Clara, and CleanPower SF to offer a standardized midstream electrification program serving multiple Bay Area counties. The program seeks to develop the electrification market by providing Bay Area residential contractors incentives for the installation of HPWHs.

The program offers a $1,000 incentive — paid directly to licensed contractors who replace homeowners’ natural gas or propane residential water heaters with high efficiency heat pump water heaters. Contractors enrolled in the BayREN Home+ program may participate in both programs and rebates are stackable. This program is self-funded by MCE and has a budget of $300,000 to install 250 HPWHs in MCE’s service area.

The HPWH Contractor Incentive Program has also created a resource of all electrification programs serving the Bay Area and has developed HPWH resources54 to help contractors and homeowners understand the benefits of this technology. MCE has contributed to a memo sharing learnings from the first year of the program, including contractor barriers to participation.55
xi. Other
MCE has no additional information in response to this sub-section xi. b. Disadvantaged Communities
In total, MCE serves 54,897 customer accounts located within DACs. This represents approximately 9.5% of MCE’s total customer accounts (approximately 580,000).

MCE is dedicated to reducing pollution impacts and encouraging the development, health, and prosperity of DAC within and outside our service area. In addition to the measures and programs described above, MCE’s commitment is reflected in the practices, programs, and policies described below.

Green Access and Community Solar Connection Programs
As described in Section d.ii., above, MCE is collaborating with the CPUC, IOUs, and other CCAs to develop community solar programs for customers in DACs. These programs will be supported 54 https://www.bayren.org/contractors/heat-pump-water-heater-hpwh-incentive-participating-contractors. 55 https://www.bayren.org/sites/default/files/2022-02/hpwh learnings may 2021 bayren 1.pdf 68 by the development of an additional 5.92 MW of new, local, clean energy capacity.

Sustainable Workforce and Diversity Policy
As described in Section d.ii., above, in 2017, MCE’s Board approved a Sustainable Workforce and Diversity Policy56 to facilitate and encourage diversity and a sustainable workforce.

More recently, in 2022 MCE adopted Sustainable Workforce Guidelines57 to create a more detailed plan for implementing its Sustainable Workforce and Diversity Policy.

These efforts have resulted in significant local developments. To date, MCE has helped build almost 48 MW of new renewable projects in our service area. All local projects over 1 MW were built with union labor. Additionally, in 2021 MCE launched two new community solar programs, Community Solar Connection and Green Access. These programs offer qualifying customers living in a CalEnviroScreen-designated DAC access to 100% renewable energy and a 20% discount on their electricity bills for up to 20 years. Both programs will be supported by the development of additional new clean energy resources.

In developing its Compliance IRP, MCE carefully considered the impact of its resource procurement on DACs. MCE’s PCP minimizes the use of fossil-based resources and unspecified system power, reducing reliance on natural gas generators that have an impact on DACs. c. Commission Direction of Actions
MCE is not seeking any specific direction of actions from the Commission at this time. However, MCE notes that it is aware of the Commission’s recent Administrative Law Judge’s Ruling Seeking Comments on Staff Paper on Procurement Program and Potential Near-Term Actions to Encourage Additional Procurement (“ALJ Ruling”).58 MCE looks forward to exploring the options for a programmatic approach to procurement to meet the goals of the IRP process as outlined in the Staff Paper on Programmatic Approaches to Electricity Procurement included with the ALJ Ruling. Whichever programmatic approach the Commission ultimately adopts, it is critical for the Commission to ensure that any new program equitably reflects an LSE’s full contribution to 56 See MCE November 16, 2017, Board of Directors Meeting Packet, Agenda Item No. 7 Attachment A https://www.mcecleanenergy.org/wp-content/uploads/2020/05/MCE-Board-Meeting-Packet-November 2017.pdf 57 See https://www.mcecleanenergy.org/wp-content/uploads/2022/05/MCE-Sustainable-Workforce-Guidelines 05122022.pdf 58 Administrative Law Judge’s Ruling Seeking Comments on Staff Paper on Procurement Program and Potential Near-Term Actions to Encourage Additional Procurement, issued September 8, 2022. 69 system reliability and achievement of California’s environmental goals and allows for flexibility to accommodate continuously evolving grid needs.

V. Lessons Learned
MCE shares the Commission’s commitment to robust and comprehensive integrated resource planning. MCE also understands the procedural and substantive complexity that defines IRP development at the state agency level and that continues through to individual LSEs as they respond to and integrate statutory and regulatory requirements into their resource planning efforts. However, in addition to the statutory requirements articulated in 454.52(a)(1)(A) -(I), MCE’s resource planning process must also give deference to its Board of Directors, which is granted statutory authority to govern MCE’s procurement and approve MCE’s IRP under 454.52(b)(3) and 366.2(a)(5). To meet all of the aforementioned statutory objectives and requirements, it is critical for MCE and other similarly situated LSEs to expect and receive timely and clear guidance from the Commission and adequate time to incorporate this guidance into its planning process. Administrative Law Judge Fitch alluded to this in the July 15, 2022 Ruling in which Energy Division Staff was directed to provide “final versions of the CSP Calculators and RDT . . .” within a reasonable period of time following July 1, 2022.59 Despite this clear guidance, updated RDTs were provided to LSEs on Friday, September 30, 2022.60 MCE appreciates these updates and the diligent work being done by Energy Division Staff, but revised templates and revised guidance this late in the process, no matter how insignificant or helpful, are disruptive to and dismissive of LSEs’ internal processes and timelines, particularly in the case of CCAs where other law governs procedure and timelines that must be followed when requesting their Boards take action. MCE urges the Commission to take steps in the next IRP cycle to adhere firmly to its timelines and the direction in its own rulings. Diligence on this front will aid all stakeholders in meeting statutory requirements and comprehensively and thoroughly addressing the state’s resource planning efforts. 59 Load Forecast Ruling issued June 15, 2022, at 14.
60 Email from Ali Eshraghi to Commission-jurisdictional LSEs, Aggregated CAM Resources for LSEs [sic] Plan Development, sent September 30, 2022; LSEs were initially advised of this update on Friday, September 23, 2022, via an email from James McGarry to Commission-jurisdictional LSEs, Notice of IRP Template Update and Q&A document [sic], sent September 23, 2022.
70 Glossary of Terms
Alternative Portfolio: LSEs are permitted to submit “Alternative Portfolios” developed from scenarios using different assumptions from those used in the Preferred System Plan with updates. Any deviations from the “Conforming Portfolio” must be explained and justified.

Approve (Plan): the CPUC’s obligation to approve an LSE’s integrated resource plan derives from Public Utilities Code Section 454.52(b)(2) and the procurement planning process described in Public Utilities Code Section 454.5, in addition to the CPUC obligation to ensure safe and reliable service at just and reasonable rates under Public Utilities Code Section 451.

Balancing Authority Area (CAISO): the collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area.

Baseline resources: Those resources assumed to be fixed as a capacity expansion model input, as opposed to Candidate resources, which are selected by the model and are incremental to the Baseline.

Baseline resources are existing (already online) or owned or contracted to come online within the planning horizon. Existing resources with announced retirements are excluded from the Baseline for the applicable years. Being “contracted” refers to a resource holding signed contract/s with an LSE/s for much of its energy and capacity, as applicable, for a significant portion of its useful life. The contracts refer to those approved by the CPUC and/or the LSE’s governing board, as applicable. These criteria indicate the resource is relatively certain to come online. Baseline resources that are not online at the time of modeling may have a failure rate applied to their nameplate capacity to allow for the risk of them failing to come online.

Candidate resource: those resources, such as renewables, energy storage, natural gas generation, and demand response, available for selection in IRP capacity expansion modeling, incremental to the Baseline resources.

Capacity Expansion Model: a capacity expansion model is a computer model that simulates generation and transmission investment to meet forecast electric load over many years, usually with the objective of minimizing the total cost of owning and operating the electrical system. Capacity expansion models can also be configured to only allow solutions that meet specific requirements, such as providing a minimum amount of capacity to ensure the reliability of the system or maintaining greenhouse gas emissions below an established level.

Certify (a Community Choice Aggregator Plan): Public Utilities Code 454.52(b)(3) requires the CPUC to certify the integrated resource plans of CCAs. “Certify” requires a formal act of the Commission to determine that the CCA’s Plan complies with the requirements of the statute and the process established via Public Utilities Code 454.51(a). In addition, the Commission must review the CCA Plans to determine ■
71 any potential impacts on public utility bundled customers under Public Utilities Code Sections 451 and 454, among others.

Clean System Power (CSP) methodology: the methodology used to estimate GHG, and criteria pollutant emissions associated with an LSE’s Portfolio based on how the LSE will expect to rely on system power on an hourly basis.

Community Choice Aggregator: a governmental entity formed by a city or county to procure electricity for its residents, businesses, and municipal facilities.

Conforming Portfolio: the LSE portfolio that conforms to IRP Planning Standards, the 2030 LSE-specific GHG Emissions Benchmark, use of the LSE’s assigned load forecast, use of inputs and assumptions matching those used in developing the Reference System Portfolio, as well as other IRP requirements including the filing of a complete Narrative Template, a Resource Data Template and Clean System Power Calculator.

Effective Load Carrying Capacity: a percentage that expresses how well a resource is able avoid loss-of-load events (considering availability and use limitations). The percentage is relative to a reference resource, for example a resource that is always available with no use limitations. It is calculated via probabilistic reliability modeling and yields a single percentage value for a given resource or grouping of resources.

Effective Megawatts (MW): perfect capacity equivalent MW, such as the MW calculated by applying an ELCC % multiplier to nameplate MW.

Electric Service Provider: an entity that offers electric service to a retail or end-use customer, but which does not fall within the definition of an electrical corporation under Public Utilities Code Section 218.

Filing Entity: an entity required by statute to file an integrated resource plan with CPUC.

Future: a set of assumptions about future conditions, such as load or gas prices.

GHG Benchmark (or LSE-specific 2030 GHG Benchmark): the mass-based GHG emission planning targets calculated by staff for each LSE based on the methodology established by the California Air Resources Board and required for use in LSE Portfolio development in IRP.

GHG Planning Price: the systemwide marginal GHG abatement cost associated with achieving a specific electric sector 2030 GHG planning target.

Integrated Resources Planning Standards (Planning Standards): the set of CPUC IRP rules, guidelines, formulas, and metrics that LSEs must include in their LSE Plans.

Integrated Resource Planning (IRP) process: integrated resource planning process; the repeating cycle through which integrated resource plans are prepared, submitted, and reviewed by the CPUC ■
72 Long term: more than 5 years unless otherwise specified.

Load Serving Entity: an electrical corporation, electric service provider, community choice aggregator, or electric cooperative.

Load Serving Entity (LSE) Plan: an LSE’s integrated resource plan; the full set of documents and information submitted by an LSE to the CPUC as part of the IRP process.

Load Serving Entity (LSE) Portfolio: a set of supply- and/or demand-side resources with certain attributes that together serve the LSE’s assigned load over the IRP planning horizon.

Loss of Load Expectation (LOLE): a metric that quantifies the expected frequency of loss-of-load events per year. Loss-of-load is any instance where available generating capacity is insufficient to serve electric demand. If one or more instances of loss-of-load occurring within the same day regardless of duration are counted as one loss-of-load event, then the LOLE metric can be compared to a reference point such as the industry probabilistic reliability standard of “one expected day in 10 years,” i.e., a LOLE of 0.1.

Maximum Import Capability: a California ISO metric that represents a quantity in MWs of imports determined by the CAISO to be simultaneously deliverable to the aggregate of load in the ISO’s Balancing Authority (BAA) Area and thus eligible for use in the Resource Adequacy process. The California ISO assess a MIC MW value for each intertie into the ISO’s BAA and allocated yearly to the LSEs. A LSE’s RA import showings are limited to its share of the MIC at each intertie.

Net Qualifying Capacity (NQC): Qualifying Capacity reduced, as applicable, based on: (1) testing and verification; (2) application of performance criteria; and (3) deliverability restrictions. The Net Qualifying Capacity determination shall be made by the California ISO pursuant to the provisions of this California ISO Tariff and the applicable Business Practice Manual.

Non-modeled costs: embedded fixed costs in today’s energy system (e.g., existing distribution revenue requirement, existing transmission revenue requirement, and energy efficiency program cost).

Nonstandard LSE Plan: type of integrated resource plan that an LSE may be eligible to file if it serves load outside the CAISO balancing authority area.

Optimization: an exercise undertaken in the CPUC’s Integrated Resource Planning (IRP) process using a capacity expansion model to identify a least-cost portfolio of electricity resources for meeting specific policy constraints, such as GHG reduction or RPS targets, while maintaining reliability given a set of assumptions about the future. Optimization in IRP considers resources assumed to be online over the planning horizon (baseline resources), some of which the model may choose not to retain, and additional resources (candidate resources) that the model is able to select to meet future grid needs.

Planned resource: any resource included in an LSE portfolio, whether already online or not, that is yet to be procured. Relating this to capacity expansion modeling terms, planned resources can be baseline ■
73 resources (needing contract renewal, or currently owned/contracted by another LSE), candidate resources, or possibly resources that were not considered by the modeling, e.g., due to the passage of time between the modeling taking place and LSEs developing their plans. Planned resources can be specific (e.g., with a CAISO ID) or generic, with only the type, size and some geographic information identified.

Qualifying capacity: the maximum amount of Resource Adequacy Benefits a generating facility could provide before an assessment of its net qualifying capacity.

Preferred Conforming Portfolio: the conforming portfolio preferred by an LSE as the most suitable to its own needs; submitted to CPUC for review as one element of the LSE’s overall IRP plan.

Preferred System Plan: The Commission’s integrated resource plan composed of both the aggregation of LSE portfolios (i.e., Preferred System Portfolio) and the set of actions necessary to implement that portfolio (i.e., Preferred System Action Plan).

Preferred System Portfolio: the combined portfolios of individual LSEs within the CAISO, aggregated, reviewed, and possibly modified by Commission staff as a proposal to the Commission, and adopted by the Commission as most responsive to statutory requirements per Pub. Util. Code 454.51; part of the Preferred System Plan.

Short term: 1 to 3 years (unless otherwise specified).

Staff: CPUC Energy Division staff (unless otherwise specified).

Standard LSE Plan: type of integrated resource plan that an LSE is required to file if it serves load within the CAISO balancing authority area (unless the LSE demonstrates exemption from the IRP process).

Transmission Planning Process (TPP): annual process conducted by the California Independent System Operator (CAISO) to identify potential transmission system limitations and areas that need reinforcements over a 10-year horizon.
■

NOVEMBER FILINGS

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
the Development of Rates and Infrastructure
for Vehicle Electrification.

Rulemaking 18-12-006
(Filed Dec. 13, 2018)

COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS
Nikhil Vijaykar
Sheridan Pauker

KEYES & FOX LLP
580 California St., 12th Floor
San Francisco, CA 94104
Telephone: (408) 621-3256
E-mail: [email protected]
On behalf of Joint Community Choice
Aggregators
November 3, 2022
i
Subject Matter Index
I. INTRODUCTION .................................................................................................................1 II. COMMENTS .........................................................................................................................2 A. LOCALLY INVESTED TRANSPORTATION ELECTRIFICATION (LITE) PILOT PROGRAM ...........2

1. An RFP process is not appropriate for the LITE program .............................................3

2. The LITE pilot program requires additional funding......................................................5

3. Recommendation regarding pilot implementation and evaluation timeline ...................6

4. Clarification regarding shortlist process and subcontracts............................................7 B. FC1 BTM REBATE PROGRAM ..............................................................................................8

1. TA for FC1 BTM Rebate Program ..................................................................................8 i. The Proposed Decision does not acknowledge, or engage with, the ample record evidence demonstrating the several benefits of CCA-administered TA. ............................8 ii. The Proposed Decision errs in finding that CCAs must participate in a Request for Proposal in order to access TA funding. .............................................................................9 iii. The Commission should require IOUs to work with the applicable CCA in developing a load management plan for a CCA customer and should require the IOU to secure CCA approval of the final load management plan.................................................10

2. ME&O for the FC1 BTM Rebate Program ...................................................................12 III. CONCLUSION....................................................................................................................12 ii
Table of Authorities
Commission Decisions
D.12-12-036...................................................................................................................................10 D.18-06-027.....................................................................................................................................4 D.22-06-005.....................................................................................................................................6 D.22-12-011...................................................................................................................................11 Commission Rules of Practice and Procedure
Rule 14.3..........................................................................................................................................1 1 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
the Development of Rates and Infrastructure
for Vehicle Electrification.

Rulemaking 18-12-006
(Filed Dec. 13, 2018)

COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS
Pursuant to Rule 14.3 of the California Public Utilities Commission’s Rules of Practice and Procedure, the Joint Community Choice Aggregators1 (Joint CCAs) hereby submit these comments on Commissioner Rechtschaffen’s October 14, 2022 Proposed Decision on Transportation Electrification Policy and Investment (Proposed Decision) in Rulemaking 18-12- 006.

I. INTRODUCTION
The Joint CCAs commend the Commission for its hard work on advancing transportation electrification (TE) policy over the last several years, including through its Proposed Decision.

The Joint CCAs support several aspects of the Proposed Decision, including in particular its focus on the medium- and heavy-duty sector (MDHD) and multi-unit dwellings (MUD),2 its emphasis on disadvantaged communities (DAC) and customers,3 and its prohibition of utility-ownership of behind-the-meter (BTM) infrastructure.4 The Joint CCAs further note that the statewide FC1 BTM Rebate Program structure that the Proposed Decision adopts includes several important elements, including the flexibility for low-income customers to receive upfront rebates;5 an “Annual 1 The Joint CCAs consist of California Choice Energy Authority (CalChoice), Clean Power Alliance of Southern California (CPA), East Bay Community Energy Authority (EBCE), Marin Clean Energy (MCE), Peninsula Clean Energy Authority (PCE), Redwood Coast Energy Authority (RCEA), San Diego Community Power (SDCP), San José Clean Energy (SJCE) and Sonoma Clean Power Authority (SCP). SJCE is the City of San José’s CCA program, which the San José Community Energy Department administers. 2 Proposed Decision (PD) at 66; 144.
3 Id. at 123-144.
4 Id. at 97-98.
5 Id. at 110. See R.18-12-006, Amended Reply Comments of the Joint Community Choice Aggregators on Energy Division Staff Proposal to Establish Transportation Electrification Funding Cycles and Statewide Behind-the-Meter Program (“Joint CCA Amended Reply Comments on Staff Proposal”) at 3-5 (May 16, 2022) (noting inadequacies of traditional rebates and highlighting record support for flexibility for low-income customer segments). The Joint 2 Roundtable” process that will facilitate changes to rebates as necessary on an annual basis;6 and a five-year funding cycle.7
The Joint CCAs strongly support the concept of the “Locally Invested Transportation Electrification” (LITE) pilot program detailed in the Proposed Decision. 8 The LITE pilot program
allows CCAs and community-based organizations (CBO) to propose TE pilots to test innovative, locally-tailored, equity-focused rebate design approaches.9 The Joint CCAs commend the Commission for recognizing the value of leveraging CCAs (and other entities that have experience working with local communities) to design and implement pilots that fit the needs of their underserved customers.

The Joint CCAs are concerned, however, that the Proposed Decision does not permit CCAs to directly administer a ratepayer-funded, locally-tailored TE program. Instead, the Proposed Decision requires that CCAs participate in a Request for Proposals (RFP), be selected by an investor-owned utility (IOU), and subcontract with an IOU in order to implement a LITE pilot.

The Joint CCAs do not agree that either an RFP process or a subcontract is necessary, as a matter of law, in order for CCAs to have the opportunity to administer ratepayer-funded programs.

Notwithstanding these concerns, CCAs may choose to pursue LITE pilots because the program is an opportunity for CCAs to deploy new and innovative TE programs for customers who need them the most. The Joint CCAs offer these comments to recommend certain targeted improvements to the structure of the LITE pilot program. The Joint CCAs also offer discrete comments on the sections of the Proposed Decision addressing the CCAs’ role with respect to marketing, education and outreach (ME&O) and technical assistance (TA) for the statewide FC1 BTM Rebate Program.

II. COMMENTS
A. Locally Invested Transportation Electrification (LITE) Pilot Program The Proposed Decision correctly recognizes that while the FC1 BTM Rebate Program is an efficient, streamlined method to fund TE infrastructure, it “may miss unique or innovative opportunities.”10 To fill gaps in the FC1 BTM Rebate Program, the Proposed Decision authorizes CCAs recommend a minor modification to Conclusion of Law 44 to clarify that up-front rebates will be permitted for low-income and DAC customers.
6 PD at 79.
7 Id. at 69.
8 Id. at 140-144.
9 Id. at 140.
10 Id.
3 up to $25 million in FC1 funding for the LITE pilot program.11 The LITE program gives CCAs, CBOs, and “other entities demonstrating experience working with local communities” the opportunity to design and implement innovative, equity-focused, locally-tailored rebates that support charging infrastructure serving low-income, disadvantaged and tribal member customers.12 The Proposed Decision directs the IOUs to issue a Request for Proposals (RFP) to select innovative LITE pilots and submit IOU-shortlisted pilots to the Commission via a Tier 3 Advice Letter (AL).
13 Once the Commission authorizes the pilots, IOUs will contract with selected entities for LITE pilot implementation over a two-year period (approximately mid-2025 through mid-2027).14
The Joint CCAs strongly support the concept of the LITE pilot program. CCAs have a demonstrated track record of designing and implementing successful TE programs tailored to the specific needs of hard-to-reach and disadvantaged customers within their service areas, and are well-positioned to scale those efforts by leveraging LITE pilot program funding.15 In this proceeding, the CCAs have submitted substantial record evidence illustrating CCAs’ expertise in administering successful programs that deliver electric vehicle (EV) and electric vehicle supply equipment (EVSE) incentives, enable wider access to charging, and provide market education, coordination, and technical assistance.16 The record also reflects CCAs’ demonstrated ability to design programs specifically to serve disadvantaged communities.17 Below, the Joint CCAs describe their concerns with the LITE program as-proposed, and offer recommendations to strengthen the program structure.

1. An RFP process is not appropriate for the LITE program The Joint CCAs’ most significant concern with the structure of the LITE program is that it does not give CCAs the opportunity to implement TE programs by directly administering ratepayer 11 Id. at 141.
12 Id. at 140.
13 Id. at 142.
14 Id. at 141.
15 See, e.g., R.18-12-006, Opening Comments of the Joint Community Choice Aggregators on Section 10 of the Energy Division Staff Proposal for a Transportation Electrification Framework at 5-8 and Attachment 1 (Sept. 11, 2020) (Joint CCAs Section 10 Comments) (providing evidence of the advantages of CCA program administration in the TE space—including CCAs’ ability to deliver programs more cost-effectively and to tailor TE solutions to local communities—and providing an Attachment with an extensive list of current CCA TE initiatives). 16 Joint CCAs Section 10 Comments, Attachment 1 (describing over thirty TE initiatives implemented by CCAs). 17 R.18-12-006, Comments of the Joint CCAs on Sections 6, 11.1, and 11.2 of the Draft Transportation Electrification Framework at 3-10 (Aug. 21, 2020).
4 funds. The Joint CCAs’ comments throughout this docket have advocated for the Commission to authorize CCAs to directly administer TE programs. TE programs are a priority for the CCAs.

CCAs have unique relationships with their customers as load-serving entities (LSE) that are responsible for serving the vast majority of load in their service areas, including EVSE. This relationship involves providing reliable service which increasingly requires load management.

CCAs need to have a meaningful role deploying EVSE in order to innovate and deliver on their role as an LSE.

The CCAs have cited substantial precedent for the administration of ratepayer-funded programs by CCAs and other non-IOU third parties.18 As the CCAs have noted in their filings in this proceeding, pursuant to its own regulatory authority, and in the absence of a specific statutory mandate, the Commission has authorized non-IOU program administration in the context of the Self-Generation Incentive Program, the California Solar Initiative, the Single-Family Affordable Solar Homes Program, the Multifamily Affordable Solar Housing Program, and the DAC Green Tariff (DAC-GT) and Community Solar Green Tariff (CS-GT) programs. 19 The DAC-GT and CS-GT programs are examples of the Commission on its own accord authorizing program administration by CCAs in particular, where such programs are approved by the Commission via AL, in the absence of express statutory authority. 20
The Proposed Decision, however, fails to engage with any of the CCAs’ record evidence or precedent on this point. The Proposed Decision also fails to engage with the Joint CCAs’ proposed alternative FC1 structure, which would have given CCAs the ability to apply via AL to apportion funding towards locally-designed and allocated incentives to meet the specific needs of underserved customers in their service areas.21 Requiring that CCAs subcontract with an IOU to implement equity-focused TE programs in their service areas is not just and reasonable, does not 18 R.18-12-006, Comments of Peninsula Clean Energy Authority on Sections 9, 10, and 12 of the Draft Transportation Electrification Framework at 12-13 (Sept. 11, 2020) (PCE Section 10 Comments); Joint CCAs Section 10 Comments at 20-21; Reply Comments of Peninsula Clean Energy Authority on Sections 9, 10, and 12 of the Draft Transportation Electrification Framework at 8-9 (Sept. 25, 2020); Reply Comments of the Joint Community Choice Aggregators on Section 10 of the Energy Division Staff Proposal for a Transportation Electrification Framework at 1-2 (Sept. 25, 2020).]
19 PCE Section 10 Comments at 12-13; Joint CCAs Section 10 Comments at 20-21. 20 D.18-06-027 at 4, 55-56, 87; see also R.18-12-006, Amended Opening Comments of the Joint Community Choice Aggregators on Energy Division Staff Proposal to Establish Transportation Electrification Funding Cycles and Statewide Behind-the-Meter Program (Joint CCA Amended Opening Comments on Staff Proposal) at 20-21 (Apr. 25, 2022) (describing the DAC-GT approval process and funding structure). 21 See Joint CCA Amended Opening Comments on Staff Proposal at 16-22 (Apr. 25, 2022). 5 reflect either the record evidence or the law, and is not appropriate in this context. In the CCAs’ experience, contracts provided by IOUs can be inappropriately one-sided and assume the IOU is the principal while the contractor performs services as its agent.22 That is an inappropriate oversight structure considering the CCAs’ direct relationship with their customers and their deep experience offering TE programs. Avoiding the administrative time and costs associated with contracting with IOUs would enable CCAs and CBOs to streamline and more impactfully utilize limited administrative budgets. Requiring CCAs enter into contracts with IOUs in order to implement LITE pilots risks undermining participation in, and the success of, the program.

Further, requiring an RFP process and contracts with the IOUs sets up the IOUs be the gatekeepers for innovation that competes against their own programs. That is problematic and raises competitive concerns. CCAs and IOUs are both in the market for retail electric service and for EVSE programs. The Commission should avoid creating a structure where one entity can effectively block their competitors from accessing funding. Under the structure in the Proposed Decision, IOUs could receive a CCA proposal and could, with full control over the RFP process, reject the offer out of hand. They could also reject a proposal to specifically prevent its innovative elements from being tested and becoming a new statewide standard. The Commission should not cement the IOU role as the incumbent EVSE provider. The Commission should embrace innovation from CCAs and not establish the IOUs as gatekeepers to funding.

Notwithstanding the CCAs’ concerns with the RFP component of the LITE pilot program’s overall structure, the Joint CCAs offer the following comments to strengthen the mechanics of the program and to ensure that it is positioned for success.

2. The LITE pilot program requires additional funding
As discussed above, the record demonstrates that CCAs are already implementing a diverse set of equity-focused TE programs, and therefore CCAs have a variety of promising ideas to contribute to the LITE pilot program.23 In order to elicit meaningful participation from potential applicants, to ensure that the pilots deployed through LITE have the opportunity to demonstrate a measurable impact, and to expand the opportunities for program administration, the Joint CCAs 22 See, e.g., R.20-11-003 Petition for Modification of Valley Clean Energy Alliance, Polaris Energy Services, and TeMix Inc. for Modification of D.21-12-015 (Jan. 31, 2022), Attachment 2 at 2-7. 23 See, e.g. Joint CCAs Section 10 Comments at Attachment 1 (describing diversity of CCA TE programs including rebate, technical assistance, managed charging, behavioral marketing, and other programs). 6 recommend that the Commission increase the budget for the LITE pilot program from $25 million to $50 million.

A larger budget will not only support the success of the LITE pilot program (by allowing more innovative pilots and more equity-focused, locally tailored TE incentives to be deployed through that program); it will also support the success of the statewide FC1 BTM Rebate Program, for two reasons. First, additional LITE pilots will provide the Commission with more information to determine potential improvements to the statewide FC1 BTM Rebate Program. Second, additional LITE pilots will diversify the opportunities to spend down the FC1 budget, mitigating the risk of a uniform program stalling and not achieving state goals.

The Joint CCAs also note that the Proposed Decision caps individual pilots at $4 million.24 The Joint CCAs do not object to that individual pilot cap; however, the Joint CCAs recommend that the Commission adopt a $10 million pilot cap for “regional LITE pilot proposals” (i.e., proposals that involve several CCAs or CBOs joining together to propose a regional LITE pilot across several CCA service areas). Regional pilots would balance the benefits of locally-tailored incentives with the administrative efficiencies of having multiple proximate entitiessharing similar customer bases collaborating on pilot applications and program delivery.

Finally, the Joint CCAs observe that the Proposed Decision caps administrative costs associated with LITE pilots to 8% of the total pilot program budget, including the contracted entity’s administrative costs as well as the IOU’s administrative costs. The Joint CCAs recommend that any IOU administrative costs associated with a LITE pilot be capped at 2% of the total pilot program budget. In the CCAs’ experience, in the absence of such a cap, there is a risk that the IOU allocates the entire administrative cost budget to itself. 25 3. Recommendation regarding pilot implementation and evaluation timeline The Proposed Decision directs the LITE pilot program to begin in 2025, concurrent with the FC1 BTM Rebate Program, and limits pilots to a two-year implementation period.26 The Proposed Decision reasons that a mid-2027 end date will allow for an evaluation of LITE pilots to occur concurrently with the Mid-Cycle Assessment.27 The Mid-Cycle Assessment will allow the 24 PD at 141. 25 See, e.g., D.22-06-005 Decision Granting in Part the January 31, 2022 Petition for Modification of Valley Clean Energy, Polaris Energy Services, and TeMix Inc. (Jun. 2, 2022) at 4-5. 26 PD at 141.
27 Id.
7 Commission to determine whether to implement, in the FC1 BTM Rebate Program, any approaches tested via LITE pilots.28
The Joint CCAs support the concept of scaling LITE pilots through the statewide FC1 BTM Rebate Program. As a practical matter, however, the Proposed Decision does not offer a feasible timeline for pilot implementation and evaluation ahead of the Mid-Cycle Assessment. In the CCAs’ experience, TE program roll-out can take several years, especially when testing new and innovative engagement forms and when working with underserved, hard-to-reach customers.

Similarly, pilot evaluation can take anywhere between 6 months and a year. Requiring LITE pilot implementation and evaluation on a two-year timeline ahead of the 2027 Mid-Cycle Assessment sets those pilots up for failure (or, at least, perceived failure). The Joint CCAstherefore recommend that the Commission establish a three-year implementation period for the LITE pilot program (pilots to begin in 2025 and end in 2028), including a six-month evaluation period. The results of LITE pilots might be addressed as a part of the Annual Roundtable occurring following the conclusion of the three-year implementation period. As a part of that process, the Commission should retain the flexibility to extend successful LITE pilots (to the extent that any the program has any remaining budget), and consider whether to authorize CCAs (and other LITE pilot administrators) to serve as program administrators for FC2 of the statewide BTM Rebate Program.

The Joint CCAs’ recommended LITE implementation and evaluation timeline would thereby ensure that pilots are set up for success, while also creating a pathway for pilots to inform the statewide program structure. The Commission should therefore adopt the Joint CCA’s recommended LITE implementation and evaluation timeline.

4. Clarification regarding shortlist process and subcontracts In addition to the structural modifications to the LITE pilot program that the Joint CCAs recommend above, the Joint CCAs also request clarification on a two narrow points. First, the Proposed Decision proposes that the IOUs submit full Implementation Plans and Program Handbooks as a part of the Tier 3 Advice Letter describing shortlisted pilots.29 While the Joint CCAs support a requirement that pilot proposals include sufficient information for the Energy Division to make an informed decision, the Joint CCAs request that the Commission clarify whether the Energy Division will be authorized to select approved bids among the shortlisted bids, 28 Id. at 140. 29 Id. at 141.
8 or whether the Energy Division will approve all shortlisted bids. To the extent that the Energy Division will be authorized to narrow shortlisted bids, a requirement that Implementation Plans and Program Handbooks be developed as a part of the shortlist process risks wasting the time and very limited administrative budget of applicants whose pilot proposals might not even be selected.

The Commission’s decision should adopt a more typical (and efficient) requirement:
implementation plans and handbooks should be developed for winning pilot proposals.

Second, the Proposed Decision designates SDG&E as the lead IOU to conduct the RFP for LITE pilots,30 but also states that the IOUs will “run” the RFP process and execute and manage any contracts for pilots in its service territory.31 If the Commission chooses the IOU-managed RFP process, the decision should be made consistent and provide that SDG&E will administer and execute the RFP for LITE pilots, select shortlisted bidders, and file the Tier 3 Advice Letter describing shortlisted bidders. Further, the Joint CCAs request that the Commission clarify that winning bidders will coordinate subcontracts with the respective IOU in their service area, and that contracts with IOUs should be narrowly focused on addressing the mechanics of fund transfers without imposing IOU managerial or supervisory authority over pilot program administrators.

B. FC1 BTM Rebate Program
As discussed above, the CCAs have consistently advocated for the opportunity to directly administer ratepayer-funded TE programs, including ME&O and TA activities. In comments on the Staff Proposal, the Joint CCAs’ recommended an alternative FC1 structure that would allow CCAs to administer ME&O and TA in support of locally-tailored incentives. The Proposed Decision does not adopt the Joint CCAs’ proposal, but it does discuss the role of CCAs with respect to ME&O and TA for the statewide FC1 BTM Rebate Program. The CCAs offer their comments in response to that discussion, below.

1. TA for FC1 BTM Rebate Program
i. The Proposed Decision does not acknowledge, or engage with, the ample record evidence demonstrating the several benefits of CCA-administered TA.

The Proposed Decision assigns TA administration as a part of the FC1 BTM Rebate Program exclusively to the IOUs, consistent with Staff’s proposal.32 In their comments, the Joint 30 Id. (“We designate SDG&E as the lead IOU to conduct the RFP.”) 31 Id. at 142 (“A competitive RFP process run by the IOUs will identify innovative pilots . . .”) 32 Id. at 113-114.
9 CCAs strongly objected to any structure that assigned TA administration solely to the IOUs. The Proposed Decision, however, finds that “the Joint CCAs have not sufficiently demonstrated the benefits of CCA administration of TA[.]”33
The record contravenes the Proposed Decision’s finding. In both opening34 and reply35 comments on the Staff Proposal, the Joint CCAs explained that CCAs currently offer a variety of TA programs that provide critical assistance to the deployment of TE for MUDs, MDHD fleets, charging needs in underserved communities, and other use cases—often filling gaps in the IOU’s programs. For instance:
• RCEA conducts fleet analyses for local governments – which are tailored to each government’s unique vehicle fleet and usage and integrate the needs and costs of various EVSE.36
• RCEA conducts site walks to help local governments assess the best siting for EVSE on their properties and upgrades necessary to support EV adoption.37 • PCE has increased the number of ports per site by 38% through its TA to charging sites located at MUDs through the use of Level 1 and load-managed Level 2 ports. PCE’s TA served to maximize charging access while minimizing the need for panel or utility service upgrades.38
• PCE’s TA to the Mercy Housing affordable housing project resulted in the development of 74 Level 1 ports and 14 Level 2 ports, at an average of $5,000 per port—which means the site host paid less than $600 per port.39
• MCE has provided TA to over 125 customer sites in their stand-alone MCE EV Charging Program for Level 1 and Level 2 EV charging.40
There is therefore ample record evidence demonstrating the “benefits of CCA administration of TA”, contrary to the Proposed Decision’s finding. The Joint CCAs recommend that the Commission correct this factual error in its final decision. ii. The Proposed Decision errs in finding that CCAs must participate in a Request for Proposal in order to access TA funding.

In its discussion of TA in support of the FC1 BTM Rebate Program, the Proposed Decision states: “it is unclear whether the Commission could award TA funding to individual CCAs without 33 Id. at 114.
34 See Joint CCA Amended Opening Comments on Staff Proposal at 14-15. 35 See Joint CCA Amended Reply Comments on Staff Proposal at 10-12. 36 Joint CCA Amended Opening Comments on Staff Proposal at 14. 37 Id. at 14-15.
38 Id. at 15.
39 Id. 40 Id.
10 putting the contract out for competitive bid . . .”41 As discussed above, the CCAs disagree that an RFP is required in order for a CCA to access ratepayer funding in order to administer a TE program (TA or otherwise). The Joint CCAs have explained, through their filings in this proceeding, that there is significant Commission precedent for the Commission authorizing CCAs and other non-IOU third parties to receive ratepayer funding to administer Commission-overseen programs via an Advice Letter process and without an RFP.42 The Joint CCAs recommend that the Commission correct this error in its final decision.
iii. The Commission should require IOUs to work with the applicable CCA in developing a load management plan for a CCA customer and should require the IOU to secure CCA approval of the final load management plan.

The Proposed Decision describes the scope of TA in support of the FC1 BTM Rebate Program as including “planning load management and other VGI considerations . . .”43 The Proposed Decision directs the IOUs to work with each customer to develop a load management plan (LMP), “which the IOU should formally approve.”44 The purpose of the LMP is to provide options that ensure that charging load is flexible and responsive to price signals. As a part of the LMP development process, the Proposed Decision directs each IOU to “work with customers to educate and provide guidance on various options for VGI and load management, including but not limited to enrollment in DR programs and deployment of ALM.”45 The Proposed Decision requires that such guidance “should be competitively neutral and should not endorse any provider or technology.”46 The Joint CCAs have several concerns with the Proposed Decision’s discussion of this issue and its related directives to the IOUs.

First, while the Proposed Decision states that guidance must be competitively neutral, this is difficult to implement as a practical matter. Even if a communication does not technically run afoul of the Code of Conduct governing the treatment of CCAs by utilities adopted in D.12-12- 036,47 having the IOUs communicate with CCA customers without coordinating with CCAs about rate options that include CCA rates and program offerings risks undermining CCA offerings. It is 41 PD at 114.
42 See supra, fn. 19.
43 PD at 116.
44 Id. at 168.
45 Id. 46 Id. 47 R.12-02-009, Code of Conduct, D.12-12-036. 11 reasonable to expect that IOUs have an interest in advancing their own rates and programs. All of the generation rates and some of the IOU’s TE programs compete with CCA programs and dual enrollment is not viable. This means customers may be led to opt out of an alternative service by IOUs and required to take retail electric service directly from the IOU as a result of the IOU’s outreach. As such, conversations with customers about the LMP are fraught with competitive issues that require close coordination between IOUs and CCAs. Fundamentally, and as the Proposed Decision acknowledges, CCAs are best suited to speak to their customers about their rate structures48—not only for competitive reasons, but also in the interest of the customer receiving accurate, comprehensive information. So, it is essential that IOUs coordinate with CCAs on customer messaging and LMPs to ensure the appropriate information is presented in a way that mitigates competitive issues to the maximum extent possible.

Second, proposing an LMP goes beyond rate education and recommendations, as it also includes program enrollments. This raises practical concerns. CCAs are currently running a variety of load-modifying and demand response (DR) programs to help customers reduce peak usage.49 DR programs include strict dual enrollment prohibitions, and therefore CCAs and IOUs are required to coordinate closely to prevent dual enrollment. This is particularly important as all current CCA DR programs are “load modifying programs” which are not integrated into the CAISO market. For those types of programs, no streamlined dual enrollment check exists. Hence, allowing the IOU to discuss and propose enrollment in DR programming without CCA involvement raises the risk of a violation of the Commission’s dual enrollment prohibition because that customer may already be enrolled in CCA load management strategies that the IOU may not be aware of. In order to prevent this from happening, CCA and IOU coordination is imperative.

The Proposed Decision however punts coordination between IOUs and the CCAs on TA generally (and presumably, on communications regarding LMP and other VGI considerations) to the Program Handbook development process. While the Program Handbook development process can and should refine the CCA and IOU roles with respect to TA delivery, the Commission should institute fundamental guardrails at this stage. The CCAs recommend that the Commission 48 PD at 114.
49 Examples include MCE’s Peak FLEXmarket (authorized by D.22-12-011 in the Commission energy efficiency proceeding R.13-11-005) and SCP’s GridSavvy DR programs , as well as ratepayer-funded EE programs with a focus on peak demand reduction. (so called “Flexmarket programs” are being run by EBCE, MCE, PCE, SCP and SJCE, all authorized under the Commission’s energy efficiency proceeding and application framework). 12 specifically include in the final decision that 1) the IOUs work with the CCA in developing a LMP for any CCA customer or any general approach to LMPs for multiple customers, and 2) the CCA be given the opportunity to review and approve each CCA customer’s final LMP.

2. ME&O for the FC1 BTM Rebate Program
The Proposed Decision correctly finds that “the involvement of CCAs in the design of the [ME&O] component [of the Statewide Program] would provide an important benefit to the program[.]”50 As the record demonstrates, the CCAs have significant expertise working with customers and local communities and carrying out effective ME&O activities.51 The Proposed Decision errs, however, where it requires that CCAs subcontract with the statewide Program Administrator in order to administer ME&O on a local level rather than allowing CCAs to directly administer ratepayer-funded TE programs (including conducting ME&O in support of those programs). CCAs should not be confined to the role of serving as marketing agencies for the IOUs or for the third-party administrator. CCAs should not be reasonably expected to market programs that they cannot control or change. CCAs have customers and are answerable to the communities they serve through their boards of elected local officials, and must protect their reputations with those customers. The IOU programs have left key programmatic gaps that result in customers being underserved. CCAs should be placed in a role to fill those gaps and add value over time, not simply relegated as marketing agents on behalf of IOU programs or in service of a cookie cutter approach with no local tailoring. The Joint CCAs therefore continue to emphasize that CCAs should have the opportunity to serve as program administrators for ratepayer-funded TE programs, including providing ME&O for such programs.

III. CONCLUSION
The Joint CCAs appreciate this opportunity to provide comments to the Proposed Decision.

The Joint CCAs’ recommended changes to the Findings of Fact, Conclusions of Law, and Ordering Paragraphs are included in Appendix A to these comments, below. 50 PD at 122.
51 Joint CCA Amended Opening Comments on Staff Proposal at 11-14. 13 Respectfully submitted,
/s/ Nikhil Vijaykar
Nikhil Vijaykar
Sheridan Pauker

KEYES & FOX LLP
580 California St., 12th Floor
San Francisco, CA 94104
Telephone: (408) 621-3256
E-mail: [email protected]
On behalf of Joint Community Choice
Aggregators
Dated: November 3, 2022
A-1

APPENDIX
Pursuant to Rule 14.3(b) of the Commission’s Rules of Practice and Procedure, the Joint CCAs provide this Appendix setting forth proposed changes to the Proposed Decision on Transportation Electrification Policy and Investment, including proposed changes to the Findings of Fact, Conclusions of Law and Ordering Paragraphs. The Joint CCAs’ proposed revisions appear in underline and strike-through.

Proposed Revisions to Findings of Fact
Modify Finding of Fact 38 as follows: “A cap of eight percent cap for both the IOUs’ and the Program Administrator’s administrative costs is reasonable based on their required program administration responsibilities. With respect to the LITE pilot program, a cap of two percent on the IOU’s administrative costs is reasonable.”
Delete Finding of Fact 57: “It is appropriate for the IOUs to maintain administration of TA – for all IOU customers, including FC0, FC1, and non-program participants, as well as bundled and unbundled customers – because TA is a part of their core responsibilities, and they are best positioned to administer the current scope of the program.” Delete Finding of Fact 58: “IOU administration of TA does not raise anti-competitive issues because TA functions involve helping customers with rates and D.12-12-036 includes an exception to marketing limitations for communications that are a part of a Commission-authorized program.” Delete Finding of Fact 60: “A split CCA- and IOU-administered TA structure would cause confusion for customers when determining with whom they should work.” Modify Finding of Fact 61 as follows: “CCAs may be are best suited to speak to their customers about their own rate structures because CCAs are can give their customers the most accurate, comprehensive information about CCA rate structures, and because any other entity speaking with CCA customers about CCA rate structures raises competitive concerns.” Add the following Finding of Fact: “CCAs are currently running load-modifying programs to help customers and the grid to reduce peak usage.”
Add the following Finding of Fact: “There are strict dual enrollment prohibitions under DR programs, so CCAs and IOUs must closely coordinate on preventing dual enrollment.” Modify Finding of Fact 69 as follows: “Involvement of CBOs and CCAs in the design and implementation of the FC1 program’s ME&O component will improve the effectiveness of ME&O due to CBOs’ and CCAs’ experience working closely with various communities and knowledge of successful outreach practices.”
A-2
Proposed Revisions to Conclusions of Law
Modify Conclusion of Law 38 as follows: “The Commission should adopt an eight percent cap for program administrative costs. With respect to the LITE pilot program, the Commission should cap the IOU’s administrative costs at two percent of the total LITE pilot program budget.”
Modify Conclusion of Law 44 as follows: “The Commission should authorize the Program Handbook to propose may include up-front rebates and any other appropriate options—beyond IOU ownership—to support low-income, DAC, and small business customers for whom the FC1 rebate model may be challenging.

Modify Conclusion of Law 75 as follows: “A budget of up to $2550 million of the total FC1 budget for the LITE pilot program is reasonable due to the potential to test new rebate design approaches that may fill gaps in the statewide program in a creative way.

Modify Conclusion of Law 76 as follows: “The Commission should require the IOUs SDG&E to conduct an RFP, and require that the IOUs execute contracts, and administer the with selected entities administering LITE pilots program according to the guidance and direction in this decision.

Modify Conclusion of Law 77 as follows: “The Commission should authorize a budget of up to $2550 million of the total FC1 budget for the initial tranche of pilots authorized as a part of the LITE pilot program, and should consider whether to fund a second tranche of pilots as a part of the LITE pilot program as a prat of the Mid-Cycle Assessment.” Add the following Conclusion of Law: “The Commission should allow a cap of $10 million for regional LITE pilots involving two or more CCAs, CBOs or other entities demonstrating experience working with local communities.”
Add the following Conclusion of Law: “The Commission should retain the flexibility to extend, modify, or terminate the initial tranche of LITE pilot projects as a part of the Mid-Cycle Assessment.”
Modify Conclusion of Law 104 as follows: “The Commission should direct the IOUs to work with each customer to develop a load management plan including ALM options, if appropriate, with details of this process to be finalized through the Program Handbook development process.

Load Management Plans for CCA customers must be approved by the relevant CCA before being implemented.”
Proposed Ordering Paragraphs
Modify Ordering Paragraph 4 as follows: “Within 60 days of the issuance date of this decision, Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & A-3
Electric Company, Liberty Utilities (CalPeco Electric) LLC, Bear Valley Electric Service Inc., and PacifiCorp d/b/a Pacific Power, collectively the investor-owned utilities (IOUs), shall each file a Tier 2 Advice Letter to establish a one-way sub-account within their existing TE balancing account or separate one-way balancing account to track costs for the Funding Cycle 1 (FC1) program. This decision approves a $1 billion budget for the FC1 program. The IOUs may access up to 60 percent of FC1 funds within the first three-years of the FC1 program, which shall begin on January 1, 2025. Each sub-account or balancing account shall be capped at $600 million for the first three years and the percentage of electric sales for the IOU in 2024. Each IOU shall disburse appropriate funds to the Program Administrator. Total FC1 rebate funding in each IOU’s service territory shall be capped based on each IOU’s funding contribution, after deducting costs for program administration, technical support and evaluations, the Locally Invested Transportation Equity (LITE) pilot program, Technical Assistance (TA) programs, and marketing, education, and outreach (ME&O) programs. For the first three years, program administrative costs, including both IOU and Program Administrator administrative expenses, shall be capped at $48 million, or eight percent of the utilized portion of the approved FC1 program budget of $600 million, whichever is lower; TA program costs shall be capped at $36 million, or six percent of the utilized portion of the approved FC1 program budget of $600 million, whichever is lower; ME&O program costs shall be capped at $36 million, or six percent of the utilized portion of the approved FC1 program budget of $600 million, whichever is lower, and costs for an IOU-managed program evaluation shall be capped at $3 million. Costs for a technical support and evaluation budget, managed by the Commission’s Energy Division (ED) staff, shall be capped at $3 million annually from 2023 through 2029, or a total of $21 million. Costs for the LITE pilot program shall be capped at $2550 million. Program Administrator costs shall be subject to audit or review by the Commission’s Utility Audit, Risk, and Compliance Division. ED staff is authorized to request additional audits or broaden the scope of the audit.”
Modify Ordering Paragraph 8 as follows: “By December 31, 2023, San Diego Gas & Electric Company (SDG&E), on behalf of itself, Pacific Gas and Electric Company, Southern California Edison Company, Liberty Utilities (CalPeco Electric) LLC, Bear Valley Electric Service Inc., and PacifiCorp d/b/a Pacific Power, collectively the investor-owned utilities (IOUs), shall issue a request for proposals for the Locally Invested Transportation Equity (LITE) pilot program.

SDG&E shall submit the shortlisted pilots to the Commission via Tier 3 Advice Letter. The Advice Letter shall include an implementation plan and a proposed pilot program handbook. The IOUs shall implement the LITE pilot program according to the guidance and direction in this decision. The LITE program shall begin no later than Q1 2025.” November 4, 2022
Internal Revenue Service
Department of Treasury
Ben Franklin Station
P.O. Box 7604, Room 5203
Washington, D.C., 20044
Re: Request for Comments on Elective Payment of Applicable Credits and Transfer of Credits – Notice 2022-50
Dear Secretary Yellen and Commissioner Rettig:

We write on behalf of Central Coast Community Energy, Clean Power Alliance, East Bay Community Energy, MCE, San Jose Clean Energy, and Silicon Valley Clean Energy to comment on the Treasury Department and Internal Revenue Service’s Notice 2022-50.

We are a collection of California-based Community Choice Aggregators (CCAs), collectively serving 4,345,215 customers across 14 counties. In California, CCAs serve more than 200 communities, more than 11 million customers, and represent 33% of the load in the state. CCAs are public agencies formed by one or more local governments to procure electricity and advance clean energy on behalf of our customers. CCAs reinvest in our communities through a wide variety of programs, with many focused on decarbonizing buildings and transportation. The Joint CCAs are also committed to providing renewable, affordable, and accessible power to our local communities, and accelerating the decarbonization of the grid in California. We are pleased to offer the following comments on the Notice:

Credit Monetization
.01 Elective Payment of Applicable Credits (§ 6417)

1. What, if any, guidance is needed to clarify which entities are applicable entities for purposes of § 6417(d)(1)(A), and which taxpayers may elect to be treated as applicable entities under § 6417(d)(1)(B), (C), or (D) for purposes of § 6417?
We would like to request explicit clarification from the IRS that CCAs qualify as “political subdivisions” for the purposes of qualifying for the direct pay provisions in the IRA. Some CCAs are formed by one local government entity and others are Joint Powers Authorities (JPA) of several cities and/or counties. Since CCAs are public agencies formed solely by units of local government and are non-taxable entities, CCAs should explicitly be eligible entities for direct pay.

The IRS should further clarify that governmental entities not subject to taxation, like CCAs, are within the definition of eligible entities. Given the broad range of governmental organizations and instruments in existence, this clarification will help ensure all such entities will be deemed eligible as intended by Congress.
4(d). Are there specific issues that the Treasury Department and the IRS should address for applicable entities that are subject to non-tax legal requirements or other rules that may affect such entities’ ability to make an election under § 6417(a)?
The IRS should also clarify that tax credits may be pledged by eligible entities as security for the payment of debt service on bonds issued to finance the project. This will allow eligible entities to rely on the tax credits under similar structures as taxable entities with confidence. It will provide issuers with greater financing flexibility and investors with greater confidence, any savings from which could be passed through to customers.

Without this clarification, there will be uncertainty with respect to the possible determination that the pledge of the tax credits constitutes a Federal guarantee on the repayment of the debt. For clarity, it is not contemplated at this time that the tax credits would be pledged as the sole security for any debt issued to finance the same qualified project.

We recommend the IRS apply the Code of Federal Rules Section 1.148-6 allocation and accounting rules for determining the use of proceeds for the 15% reduction in the value of the tax credits when projects are financed with tax-exempt debt.

Finally, the IRS should establish a “look-through” rule with respect to sales of energy to related parties. Two examples of related parties include: (1) a bond issuer created by a member for the purpose of prepaying electricity, or (2) a joint purchasing authority (e.g. a JPA) on behalf of multiple CCAs.

CCAs have formed such entities to reduce costs, the savings from which ultimately benefit consumers. The look-through rule should clarify that the energy sold at the retail level to the public should count as the initial sale of energy. As such, sales from one eligible entity to a related party should not count as the initial sale under the IRS rules. This approach is used under the IRS rules related to Clean Renewable Energy Bonds, and for the same reason we request it here.

8. Section 6417(d)(4)(A) provides that, in the case of any government, or political subdivision described in § 6417(d)(1), and for which no return is required under § 6011 or 6033(a), the payment described in § 6417(a) is treated as made on the later of the date that a return would be due under § 6033(a) if such government or subdivision were described in § 6033(a) if such government or the date on which such government or subdivision submits a claim for credit or refund at such time and in such manner as the Secretary provides. What factors should the Treasury Department and the IRS consider when providing guidance to clarify the timing and manner of a payment made by these governments or political subdivisions? We request that direct pay is implemented in a way that is easy and clear for users. For example, the IRS should consider developing a simple tax form intended for use by tax-exempt entities pursuing direct pay. Additionally, we would like clarity on the timeline of direct pay, including how long it will take for the IRS to provide direct pay payments, so we can plan accordingly.

Direct pay returns should be subject to the same speed and level of scrutiny as tax credit returns. The timing for direct pay elections should be as late as possible, as numerous factors can impact the finances and operation of any project up to the date it is actually placed in service. We also request that if the entire output of a facility is under a long-term contract (greater than 10 years) to an applicable entity (such as a CCA) but is not owned by the applicable entity, that the receipt of the direct pay can be made directly to the applicable entity (the purchaser of the output).

Thank you for considering our comments. We look forward to continuing to work with the Treasury and IRS on implementation of this historic investment in clean energy and decarbonization.

Sincerely,
Brian Kimball
General Counsel
Central Coast Community Energy
Ted Bardacke
CEO
Clean Power Alliance
Nick Chaset
CEO
East Bay Community Energy
Dawn Weisz
CEO
MCE
Lori Mitchell
Director
San Jose Clean Energy
Girish Balachandran
CEO
Silicon Valley Clean Energy
November 4, 2022
Internal Revenue Service
Department of Treasury
Ben Franklin Station
P.O. Box 7604, Room 5203
Washington, D.C., 20044
Re: Request for Comments on Prevailing Wage, Apprenticeship, Domestic Content, and Energy Communities Requirements – Notice 2022-51
Dear Secretary Yellen and Commissioner Rettig:

Credit Enhancements
.03 Domestic Content Requirements

5. Please provide comments on any other topics relating to the domestic content requirements that may require guidance.

The joint CCAs are also very supportive of the focus on domestic content requirements through the IRA. However, there are limitations on the speed and scale of repatriating domestic manufacturing required to accelerate the transition to a low carbon economy. It is imperative that the domestic content requirements are phased in a timely manner such that domestic manufacturing can scale to meet the demand for renewable energy - and the need to address climate change - without causing inflationary pressure on the goods being sold to American businesses and citizens. We request that the federal government consult with industry to understand domestic content limitations and timing to bring manufacturing back to the Nation such that there is a smooth ramp, continued progress on decarbonization, and limited inflationary pressure on pricing.

Thank you for considering our comments. We look forward to continuing to work with the Treasury and IRS on implementation of this historic investment in clean energy and decarbonization.

Sincerely,
Brian Kimball
General Counsel
Central Coast Community Energy
Ted Bardacke
CEO
Clean Power Alliance
Nick Chaset
CEO
East Bay Community Energy
Dawn Weisz
CEO
MCE
Lori Mitchell
Director
San Jose Clean Energy
Girish Balachandran
CEO
Silicon Valley Clean Energy
506181531.2
November 4, 2022
The Honorable Janet L. Yellen
U.S. Secretary of the Treasury
Internal Revenue Service
CC:PA:LPD:PR (Notice 2022-50)
Room 5203, P.O. Box 7604
Ben Franklin Station, Washington, D.C., 20044
Re: Notice 2022-50, Request for Comments on Elective Payment of Applicable Credits and Transfer of Certain Credits
Dear Secretary Yellen:

Marin Clean Energy (“MCE”) hereby submits these comments in response to the U.S. Department of the Treasury’s (“Treasury”) above referenced request for comments to issue guidance regarding the elective payment provisions under Code1 Section 6417 and the elective credit transfer provisions Code Section 6418, as added by Section 13801 of Public Law 117-169, 136 Stat. 1818 (August 16, 2022), commonly known as the Inflation Reduction Act of 2022 (“IRA”).

MCE is a California Community Choice Aggregator (“CCA”) and California Joint Power Authority (“JPA”) that provides electricity generation service to approximately 575,000 customer accounts across 37 Bay Area communities. Established in 2002 by AB 117,2 California’s CCA program allows for communities to join together as public agencies to purchase electricity and advance clean energy on behalf of community members. CCAs reinvest in our communities through a wide variety of programs, with many focused on energy efficiency, demand reduction, and decarbonizing buildings and transportation.

MCE has been committed to environmental justice since its launch in 2010 and continues to work with member communities to advance equity through tailored programs and services. MCE has prioritized equitable access to clean energy benefits that support customers who have been underserved by traditional energy programs or who are most impacted by the frontline effects of fossil fuel generation.
1 All references to the “Code” herein are to the Internal Revenue Code of 1986, as amended and restated. 2 AB 117 was codified in several separate sections of the California Public Utilities Code, notably sections 331.1, 381.1, 366.2, and 707. In 2011, SB 970 strengthened the CCA program by prohibiting utilities from marketing against CCAs except through a separate marketing division that is separated from the utility’s other operations. In 2016, AB 1110 established a greenhouse gas emission (“GHG”) disclosure framework that applies to all electricity providers, including CCAs.
506181531.2
I. Treasury should confirm in guidance that CCAs are applicable entities within the meaning of Code Section 6417(d)(1)(A)(ii)
Code Section 115 states “gross income does not include income derived from any public utility or the exercise of any essential government function and accruing to a State or any political subdivision thereof, or the District of Columbia.”
CCAs are authorized pursuant to California Public Utilities Code Sections 331.1, 381.1, 366.2, and 707. As such, each CCA is a political subdivision of the state of California, constitutes a public utility, and exercises an essential government function. Income earned by the CCA in the performance of its services of providing electricity to customers is therefore exempt.

Given that a CCA is a political subdivision of the State of California, it is clearly also an “applicable entity” under Code Section 6417(d)(1)(A)(ii) and may benefit from the election for direct payment of applicable credits under Code Section 6417. However, with the unique nature of CCAs, MCE requests that Treasury specifically note in guidance issued under Code Sections 6417 and 6418 that CCAs qualify as “political subdivisions” and therefore are applicable entities for purposes of elective payment and credit transfers, respectively.

Confirming that CCAs are applicable entities will avoid uncertainty and further encourage CCA participation in advanced clean energy projects. By pooling the purchasing power of the communities served by a CCA, CCAs benefit those communities by managing local energy rates, encouraging local job creation within the areas served by the CCAs, and promoting greater renewable energy development through aggressive GHG-reduction goals and targets. Making it clear that CCAs are applicable entities for purposes of Code Section 6417 will provide additional incentives for CCAs to invest in clean energy projects within their jurisdictions and accelerate the adoption of clean energy generation and storage facilities by CCAs.

II. Direct pay guidance applicable to state and political subdivisions should be simple and coordinated with other federal grant programs to the maximum extent possible MCE requests that direct pay be implemented in a way that is clear and administrable. Organizations that are exempt from tax pursuant to Code Section 501 may elect direct pay in the context of routine annual reporting on Form 990. However, this process is more difficult for States, political subdivisions, and tribes, all of which are government organizations that are generally not subject to U.S. federal income tax and generally do not file with the Internal Revenue Service (“IRS”) other than in respect of employment taxes.

MCE suggests that IRS should develop a simple form or mechanism that States, political subdivisions, and tribes may use to claim direct pay. This could take a few forms. For example, IRS could adapt the method currently used by disregarded entities that are owned by a foreign person, e.g., a Form 1120 with identifying information only that accompanies a separate form that includes substantive information, for example, Form 3468 or Form 8835.
506181531.2
Treasury should scrutinize elections under Code Section 6417 and the corresponding property using a level of review that is no higher than that applied to taxable organizations and their tax credit-qualified property. In addition, Treasury should not select for audit returns solely within the pool of direct pay elections, but include those elections in the total audit pool for federal income tax credits.

Treasury should also quickly clarify filing deadlines for States, political subdivisions, and tribes. These organizations generally do not file federal income tax returns, so existing return deadlines are generally meaningless for them. Moreover, there is no reason why these organizations could not submit an election for direct pay at or immediately after the time property or a facility is placed in service or even before that time. MCE urges Treasury to think creatively about how to not only collect election requests, but also how early a state, political subdivision, or tribe must file an election for direct pay.

Finally, Treasury should expedite payment in the context of Code Section 6417 elections. These payments are not refunds and should not be processed in the context of other refunds. Rather, direct payments should be paid quickly after IRS receives a Code Section 6417 election and in a manner similar to that used for the prior 1603 grant program. In many cases, the electing organization will have been forced to obtain bridge financing to cover the gap between other funding sources and direct pay. The longer that a CCA or any government organization must carry bridge financing, the longer the people in those jurisdictions must bear the cost to install renewable energy property designed to benefit them. A long waiting period between filing a direct pay election and obtaining the capital only imposes additional burdens on the people of the United States and delays their opportunity to benefit from the federal government’s drive to accomplish the transition to clean energy.

III. Treasury should expressly provide that eligible entities may pledge their credits as security for the payment of debt service on bonds
MCE requests that Treasury also confirm that direct payments of tax credits may be pledged by applicable entities as security for the payment of debt service on bonds issued to finance clean energy. This is generally permitted in the context of refunds and investor capital contributions in respect of tax credits.

Without certainty around this point, it will be more difficult for MCE and other applicable entities to obtain financing to close the gap in time between when payments on a project are due and the direct payment is made. This would, of course, reduce the chance that applicable entities may use direct pay and lead the energy transition.

IV. Treasury should allocate tax-exempt bonds to the property that qualifies for the tax-exempt financing when calculating a reduction in the amount of tax credit available and, therefore, the amount of direct pay available
Tax-exempt bonds are generally available only in respect of certain types of property. In many cases, that property may constitute only a portion of a complete system that otherwise qualifies for tax credits. This is a concern for taxable organizations, but is of particular importance for states and political subdivisions because projects built by them are often funded at least in part with exempt bonds. 506181531.2
Most of the new income tax credits include language that indicates that those tax credits will be reduced proportionately (up to 15%) when tax-exempt loans are used to finance the qualified property or facility.

This is a particularly acute issue in the context of investment tax credit-style credits, e.g., Code Section 48 and 48E, when an exempt bond can only be issued in respect of a portion of the property comprising a whole system. Particularly in that case, Treasury should clarify in guidance that available credits will be reduced only in respect of the that portion of the qualified property integrated into a complete project (or that portion of the property integrated into a facility) that may be funded by any exempt bond proceeds.

V. Treasury should confirm in guidance that an eligible entity for purposes of Code Section 6418 may transfer eligible tax credits to an applicable entity and the applicable entity may then elect direct pay under Code Section 6417
CCAs and many other political subdivisions purchase power from renewable energy generation facilities as a way to both serve customers’ energy needs and further decarbonization goals. Power purchase agreements are essential for financing projects and placing them in service. Monetizing tax credits are also essential. (These points are also true for hydrogen and biogas production facilities.) Combining these two transactions will significantly reduce transaction costs and dramatically accelerate the time to place renewable energy projects in service.

By excluding applicable entities (i.e., entities that may use direct pay) from the definition of eligible taxpayers (i.e., persons permitted to transfer tax credits), Code Section 6418(f)(2) bars applicable entities from transferring tax credits. However, nowhere does Code Section 6418 provide that eligible taxpayers may not transfer tax credits to applicable entities. Moreover, Code Section 6417 allows any applicable entity to elect direct pay “with respect to any applicable credit determined with respect to such entity.” (Emphasis added.) As used, “determined with respect to” appears to mean that an applicable credit is available to an applicable entity, i.e., it is determined that the applicable entity qualifies for the credit.

Given that Code Section 6418(a) specifies that “the transferee taxpayer specified in such election (and not the eligible taxpayer) shall be treated as the taxpayer for purposes of this title with respect to such credit (or such portion thereof),” it seems clear that an eligible credit is “determined with respect to” the transferee of that credit. Accordingly, there seems to be no impediment to an applicable entity such as a CCA paying cash to an eligible taxpayer in consideration for a tax credit that is both an eligible credit for Code Section 6418 and an applicable credit for Code Section 6417 and then electing direct pay in respect of that credit.

Given that there is some disagreement in the community about the interplay of Code Section 6418 and 6417, MCE urges Treasury to issue clear guidance interpreting these provisions in this context. In MCE’s view, Code Section 6417 and 6418 permit MCE to purchase eligible credits from an eligible taxpayer and then elect direct pay in respect of such credits (assuming they are also applicable credit). MCE urges Treasury to adopt this view for the reasons stated above. 506181531.2
VI. When evaluating the sale of energy to related parties, Treasury should adopt a “look-through” rule under which certain controlled entities are treated as agents rather than as separate entities for purposes of determining when the initial sale of energy occurs MCE requests Treasury establish a “look-through” rule with respect to sales of energy to related parties.

Two examples of related parties include: (1) a bond issuer created by a member for the purpose of prepaying electricity, or (2) a joint purchasing authority (e.g. a JPA) on behalf of multiple CCAs.

The look-through rule should clarify that the energy sold at the retail level to the public should count as the initial sale of energy and that the transfer of energy from a related party (e.g. a bond issuer or a joint purchasing company) to a CCA not be treated as a “sale” of energy for purposes of determining credit eligibility. This approach is used under the IRS rules related to Clean Renewable Energy Bonds, and for the same reason we request it here.

Thank you for considering MCE’s comments. MCE looks forward to continuing to work with the Treasury and IRS on implementation of this historic investment in clean energy and decarbonization.

Sincerely,
Nathaniel Malcolm
Senior Policy Counsel
Marin Clean Energy
I. DocuSigned by:

L~i.~
506172430.2
November 4, 2022
The Honorable Janet L. Yellen
U.S. Secretary of the Treasury
Internal Revenue Service
CC:PA:LPD:PR (Notice 2022-51)
Room 5203, P.O. Box 7604
Ben Franklin Station, Washington, D.C., 20044
Re: Notice 2022-51, Request for Comments on Prevailing Wage, Apprenticeship, Domestic Content, and Energy Communities requirements Under the Act Commonly Known as the Inflation Reduction Act of 2022
Dear Secretary Yellen:

Marin Clean Energy (“MCE”) hereby submits these comments in response to the U.S. Department of the Treasury’s (“Treasury”) above referenced request for comments to issue guidance regarding the provisions of §§ 30C, 45, 45L, 45Q, 45U, 45V, 45Y, 45Z, 48, 48C, 48E, and 179D of the Internal Revenue Code (“Code”), as amended or added by Public Law 117-169, 136 Stat. 1818 (August 16, 2022), commonly known as the Inflation Reduction Act of 2022 (“IRA”).

MCE is a California Community Choice Aggregator (“CCA”) and California Joint Powers Authority that provides electricity generation service to approximately 575,000 customer accounts across 37 Bay Area communities. Established in 2002 by AB 117,1 California’s CCA program allows for communities to join together as public agencies to purchase electricity and advance clean energy on behalf of community members. CCAs reinvest in our communities through a wide variety of programs, with many focused on energy efficiency, demand reduction, and decarbonizing buildings and transportation.

I. Treasury should clearly distinguish between products that are considered iron or steel and products that are considered manufactured products for purposes of the domestic content requirements.

In the interest of providing taxpayers and their suppliers clear and concise definitions so they can confidently invest in new clean energy projects, MCE strongly recommends that Treasury clearly distinguish between products that are considered to be iron and steel and items that are considered to be manufactured products under the domestic content requirements. This is important because the required percentages of steel and iron (100%) are significantly higher than those for manufactured products (40%), in each case, across a facility. For political subdivisions such as MCE, a failure by 1 AB 117 was codified in several separate sections of the California Public Utilities Code, notably sections 331.1, 381.1, 366.2, and 707. In 2011, SB 970 strengthened the CCA program by prohibiting utilities from marketing against CCAs except through a separate marketing division that is separated from the utility’s other operations. In 2016, AB 1110 established a greenhouse gas emission (“GHG”) disclosure framework that applies to all electricity providers, including CCAs.
506172430.2
manufacturers or suppliers to meet these thresholds is not just a matter of forgoing an increased credit rate. Rather, a failure to meet them will result in a 10% reduction in available direct payments to MCE and other similarly situated entities beginning with facilities that begin construction in 2024 or later.2 Code Section 45(b)(9)(B)(ii)3 points to 49 C.F.R. 661.5 to define what steel and iron are for purposes of the domestic content requirements. The language in 49 C.F.R 661.5(c) is quite broad, but ill-suited for the task at hand. The subsection provides that “[t]he steel and iron requirements apply to all construction materials made primarily of steel or iron and used in infrastructure projects such as transit or maintenance facilities, rail lines, and bridges.” However, this definition does not address renewable energy facilities-- which are not infrastructure projects--and the role that steel and iron components play in them. Simply put, Treasury must separately define steel and iron for purposes of the domestic content bonus credits or taxpayers will be stiffled by the lack of certainty about how to interpret 49 C.F.R. 661.5 in the context of renewable energy facilities.

MCE urges Treasury to specify in guidance that in the context of any property or facility described in any of the Code provisions included in the IRA, steel or iron is any component made primarily of steel or iron that has solely a structural, load-bearing, or support function for the property or facility. In this context, construction materials made primarily of steel or iron should include only those components described in the immediately preceding sentence when the steel or iron content of such materials is greater than 80 percent.

Code Section 45(b)(9)(B)(iii) describes manufactured products, but does not define the concept generally or by reference to 49 CFR 661. MCE recommends that Treasury clearly define “manufactured product” to mean any item produced as the product of a manufacturing or fabrication process and expressly include in that definition any property incorporated into a qualified facility or energy property that is not steel or iron, as defined above. For this purpose, “Manufacturing or fabrication process” should be defined as the application of processes to alter the form or function of materials or of elements of tangible property in a manner that transforms those materials or property this is functionally different. For example, manufacturing or fabrication processes may include forming, extruding, bending, material removal, welding, soldering, etching, plating, material deposition, pressing, permanent adhesive joining, shot blasting, brushing, grinding, lapping, finishing, vacuum impregnating, and, in electrical and electronic pneumatic, or mechanical products, the collection, interconnection, and testing of various elements.

Finally, MCE urges Treasury to confirm in guidance that the waiver provisions set out in 49 CFR 661.7 are available for purposes of applying the domestic content requirements and setting forth a method of process for asking for a waiver under the circumstances described therein. MCE observes that Code Section 45(b)(10)(D) provides for certain waivers or relaxation of the domestic content requirements in certain circumstances. While this is appreciated, these waivers are quite specific and narrow. However, they are clearly not exclusive. Code Section 45(b)(10)(B)(i) refers to 49 C.F.R. 661 generally for purposes of determining if steel, iron, or manufactured products were “produced in the United States”. 49 C.F.R. 661.7, which is a part of 49 C.F.R. 661, describes a waiver process applicable to four specific instances, 2 Code Section 45(b)(10)(C). Other Code sections that utilize domestic content ultimately point to this provision for the same purpose.
3 All of the Code sections that utilize a domestic content bonus amount ultimately point to this provision. 506172430.2
none of which are duplicated in Code Section 45(b)(10)(D). This waiver process applies to steel, iron, and manufactured products. Thus, Code Section 45(b)(10)(D) should be interpreted as an expansion of the class of circumstances in 49 C.F.R. 661.7 in which a waiver will be available, and not as an exclusive list of the circumstances in which a waiver will be available.

II. Treasury should adopt clear and administrable rules and documentation requirements for establishing when a manufactured product is manufactured in the United States.

Most manufactured products are complex components comprised of multiple parts or subcomponents.

In many cases, it may be very difficult to determine where any single part or subcomponent originated or was manufactured or fabricated. Accordingly, MCE recommends that Treasury publish clear and administrable rules for establishing when a manufactured product is manufactured in the United States.

To set the context, it is important to have in mind the precise language in Code Section 45(b)(9)(B)(iii):

For purposes of clause (i), the manufactured products which are components of a qualified facility upon completion of construction shall be deemed to have been produced in the United States if not less than the adjusted percentage (as determined under subparagraph (C)) of the total costs of all such manufactured products of such facility are attributable to manufactured products (including components) which are mined, produced, or manufactured in the United States.

This statutory language clearly indicates that manufactured products and portions of those manufactured products that constitute components must be evaluated to determine if such components have been mined, produced, or manufactured in the United States. The statute does not require an analysis of the items of property that comprise a component. The statutory language also clearly indicates that it is sufficient that components be “mined, produced, or manufactured in the United States” (emphasis added).

To create a clear and administrable rule in this regard, Treasury must first distinguish between manufactured products, components, and items of property that are incorporated into components, which MCE refers to here as subcomponents. MCE’s proposal for the definition of manufactured product appears above. MCE further recommends that Treasury define “component” to mean manufactured products, articles, materials, or supplies that are separately delivered to the project site and incorporated into or affixed to the qualified facility or energy property and “subcomponent” to mean an individual part that is incorporated into a component during a manufacturing, fabrication, or assembly process.

Then, Treasury must provide to taxpayers a method for calculating when a component is made in the United States for purposes of Code Section 45(b)(9). As noted above, it can be extremely difficult to determine whether each individual item in a component was mined, produced or manufactured. To ensure that taxpayers can realistically utilize the domestic content bonus credit, Treasury must both ensure that a taxpayer can prove compliance and that compliance is achievable. Thus, as an initial matter, MCE recommends that Treasury provide in guidance that any component is considered to be mined, produced, or manufactured in the United States if the component was manufactured, fabricated, or assembled in the United States, regardless of where its subcomponents originate. 506172430.2
Further, the rule adopted by Treasury should provide for a minimum threshold percentage for each component integrated into a manufactured product that must be met in order for the manufactured product as a whole to be treated as mined, produced, or manufactured in the United States. This allows suppliers a margin of error in calculating whether a component was mined, produced, or manufactured in the United States. This margin of error is very important for purposes of ultimately financing the installation of a renewable energy facility because there is no reasonable cause or “fail safe” mechanism in case of inadvertent error in calculating qualification for the domestic content bonus credit. Moreover, obtaining assurances about very rigid information in complex supply chains is extremely difficult in the context of negotiating tax equity investment. If developers and project owners are forced to meet unreasonably rigid requirements concerning whether manufactured products are mined, produced, or manufactured in the United States in order to get tax equity investors (or transferees of tax credits under Code Section 6418) comfortable enough to invest, there is a very material chance that developers will simply stop attempting to utilize the domestic content bonus credit.

For these reasons, MCE recommends that Treasury publish in guidance a safe harbor that specifies that any item that is a manufactured product shall be deemed to have been mined, produced, or manufactured in the United States if all of the manufacturing processes resulting in the conversion of components into a manufactured product took place in the United States. For this purpose, care should be taken to define manufacturing processes consistently with the concept of production of items of property under Code Section 45X.

A taxpayer should also have the ability to otherwise demonstrate that a manufactured product was mined, produced, or manufactured in the United States, e.g., by making available documentation that the minerals or metallurgical ingredients used to produce a manufactured product were extracted or processed in the United States. In this case, the taxpayer should be required to demonstrate that the manufactured product was either mined, produced, or manufactured in the United States, in each case by reference to a threshold amount of the subcomponents incorporated into a manufactured product.

For example, if a taxpayer can document that more than 50% of the subcomponents that comprise the biogas cleaning equipment installed at a biogas production facility were manufactured in the United States, all such biogas cleaning equipment, assuming it is a manufactured product, should qualify as mined, produced, or manufacturing in the United States.

MCE further recommends that in determining the origin of each subcomponent, each subcomponent must be treated as either entirely domestic or entirely foreign, based on the place where the component is mined, produced, or manufactured. Furthermore, the individual costs of subcomponents, even if of foreign origin, should be included in the cost of a component that is mined, produced, or manufactured in the United States.

III. Treasury should utilize standard beginning of construction rules for purposes of determining when a project is not required to meet the prevailing wage and apprenticeship requirements Code Section 48(a)(9) states that the base credit rate shall be multiplied by five times when certain prevailing wage and apprenticeship requirements are met. However, Code Section 48(a)(9)(B)(iii) states ----
506172430.2
that these requirements will apply only to “a project the construction of which begins” before that day that is 60 days after Treasury publishes guidance concerning the prevailing wage and apprenticeship requirements. However, any guidance that Treasury releases must address not only the prevailing wage and apprenticeship requirements, but also the meaning of “the construction of which begins.” This phrase, as used in Code Section in Code Section 48(a)(9)(B)(iii), is exactly the same as the statutory language used in the sunset provisions of various current and prior iterations of Code Section 48.

Accordingly, MCE urges Treasury to issue guidance concerning this standard that is substantively identical to prior guidance interpreting this concept and to new guidance interpreting this concept in other circumstances under Code Section 48.

The existing beginning of construction rules are well established. They are familiar to and understood by both taxpayers and the IRS. The certainty that using established rules provides cannot be understated.

Clear and understood rules provide the predictability that financing parties require and that helps developers grow their businesses so that they can build more renewable energy facilities.

For these reasons, the MCE suggest that Treasury issue guidance combining the beginning of construction rules in Notice 2018-59 and Notice 2021-41 and specifying a four-year continuous construction safe harbor. The MCE further suggest that Treasury also specifically state in this guidance that after a taxpayer acquires safe harbored property, any actions taken that would constitute continuous construction demonstrate sufficient development of a project such that safe harbored equipment may be transferred to an unrelated person.4
Implementing new beginning of construction rules would create unnecessary uncertainty regarding interpretation that will reduce the attractiveness of the new credits and increase administrative burden for the IRS. In addition, issuing beginning of construction rules in the context of the prevailing wage and apprenticeship requirements that are different from those in other contexts under Code Section 48 would be confusing for taxpayers and only lead to inadvertent and unnecessary error. Moreover, new or different rules are not warranted either under principles of statutory interpretation or for any apparent policy reason. Accordingly, MCE urges Treasury to utilize the existing and understood rules concerning beginning of construction in Notices 2018-59 and 2021-41 in the context of the prevailing wage and apprenticeship requirements under Code Section 48(a)(9) and similar contexts in other sections of the Code concerning U.S. federal income tax credits.
4 See Section 8 of Notice 2018-59.
506172430.2
Thank you for considering MCE’s comments. MCE looks forward to continuing to work with the Treasury and IRS on implementation of this historic investment in clean energy and decarbonization.

Sincerely,
Nathaniel Malcolm
Senior Policy Counsel
Marin Clean Energy
I. DocuSigned by:

L~i.~~
November 4, 2022
Internal Revenue Service
Department of Treasury
Ben Franklin Station
P.O. Box 7604, Room 5203
Washington, D.C., 20044
Re: Request for Comments on Certain Energy Generation Incentives – Notice 2022-49
Dear Secretary Yellen and Commissioner Rettig:

Energy Generation Incentives
.01 IRA Changes to the Renewable Electricity Production Credit (§45) and .02 The Energy Investment Credit (§48)

4. Please provide comments on any other topics relating to the §45 credit that may require guidance. Please provide comments on any other topics relating to the §48 credit that may require guidance.

Bonus tax credits for the Investment Tax Credit and Production Tax Credits are appreciated, but the Treasury and IRS should endeavor to make the guidance for layering these credits as simple as possible. Overcomplexity may create unnecessary administrative spending and backlogs, as well as prohibit smaller entities from engaging.

Thank you for considering our comments. We look forward to continuing to work with the Treasury and IRS on implementation of this historic investment in clean energy and decarbonization.

Sincerely,
Brian Kimball
General Counsel
Central Coast Community Energy
Ted Bardacke
CEO
Clean Power Alliance
Nick Chaset
CEO
East Bay Community Energy
Dawn Weisz
CEO
MCE
Lori Mitchell
Director
San Jose Clean Energy
Girish Balachandran
CEO
Silicon Valley Clean Energy
November 4, 2022
Internal Revenue Service
Department of Treasury
Ben Franklin Station
P.O. Box 7604, Room 5203
Washington, D.C., 20044
Re: Request for Comments on Incentive Provisions for Improving the Energy Efficiency of Residential and Commercial Buildings – Notice 2022-48
Dear Secretary Yellen and Commissioner Rettig:

Incentives for Homes and Buildings

1. The Treasury Department and the IRS request comments on questions arising from the amendments made by the IRA to §§ 25C, 25D, 45L, and 179D. Commenters are encouraged to specify the issues on which guidance is needed most quickly as well as the most important issues on which guidance is needed.

Ease of Use
As the IRS, Treasury and Federal Departments issue guidance and program rules, we would like to center the consumer experience to ensure that it is easy for people to understand and use the various rebates and tax credits.

Federal implementing agencies and departments should expressly direct state implementing and/or administering energy agencies to permit and support layering of federal and non-federal incentives, including but not limited to tax credits. We recommend that DOE partner with IRS and Treasury as an implementing agency to help ensure smooth and comprehensive coordination.

The federal government should allow and encourage regional administrators to distribute rebate funds. This would allow states to place funds administration close to the customer for integration with existing programs.

Integration with existing programs will enable efficiently layering local and federal incentives without need for multiple applications across different entities which typically results in added overhead and confusion for end customers.

Tenant and Low-income Consumer Access
Tenants and low-income consumers should be key beneficiaries of the IRA’s consumer-focused programs. We would like all decarbonization tax credits and rebates to be explicitly allowed for residential and commercial tenants.

On tax credits, IRS clarity on how low-income customers can access benefits if they do not have a tax liability would be helpful. Additionally, the IRS and Treasury should adopt guidelines that make it easy for tenants to understand and access the incentives without needing to use a tax advisor. .01 Energy Efficient Home Improvement Credit (§25C)

4. Please provide comments on any other topics relating to the §25C credit that require guidance:

In high-cost areas like California, the rebates and tax credits in the IRA may not go as far to cover the labor and equipment costs as in other parts of the county. Therefore, we ask that the guidance allows HOMES or HEERA rebates to stack with 25C Residential Energy Efficiency Home Improvement Tax Credit. Additionally, we request clarity that the 25C tax credit allows for a $2,000 heat pump tax credit and an additional $1,200 for other improvements in one tax year. The ability to stack these tax credits makes it easier for low-income households to afford electrification improvements.

Thank you for considering our comments. We look forward to continuing to work with the Treasury and IRS on implementation of this historic investment in clean energy and decarbonization.

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
the Development of Rates and Infrastructure
for Vehicle Electrification.

Rulemaking 18-12-006
(Filed Dec. 13, 2018)

REPLY COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS ON

PROPOSED DECISION ON TRANSPORTATION ELECTRIFICATION POLICY AND

INVESTMENT
Nikhil Vijaykar
Sheridan Pauker

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue
the Development of Rates and Infrastructure
for Vehicle Electrification.

Rulemaking 18-12-006
(Filed Dec. 13, 2018)

REPLY COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS ON

PROPOSED DECISION ON TRANSPORTATION ELECTRIFICATION POLICY AND

INVESTMENT
Pursuant to Rule 14.3(d) of the California Public Utilities Commission’s Rules of Practice and Procedure, the Joint Community Choice Aggregators1 (Joint CCAs) hereby reply to opening comments on Commissioner Rechtschaffen’s October 14, 2022 Proposed Decision on Transportation Electrification Policy and Investment (Proposed Decision).

The Joint CCAs’ opening comments on the Proposed Decision expressed strong support for the “Locally Invested Transportation Electrification” (LITE) pilot program described in the Proposed Decision.2 The LITE pilot program is a critical component of FC1’s equity strategy because it allows CCAs (and other entities that have experience working with local communities) the opportunity to fill gaps in the statewide BTM Rebate Program and test innovative rebate design approaches that are tailored to meet the needs of underserved customers.3 San Diego Gas & Electric Company (SDG&E) is the only party that objects to Commission approval of the LITE pilot program.4 SDG&E’s opposition to the LITE pilot program is based in part on the inaccurate factual premise that LITE pilots would serve only unbundled customers. As the Joint CCAs explain in these reply comments, the Commission should disregard this argument 1 The Joint CCAs consist of California Choice Energy Authority, Clean Power Alliance of Southern California, East Bay Community Energy Authority, Marin Clean Energy, Peninsula Clean Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San José Clean Energy (SJCE) and Sonoma Clean Power Authority. SJCE is the City of San José’s CCA program, which the San José Community Energy Department administers.
2 R.18-12-006, Comments of the Joint Community Choice Aggregators at 3-9 (Nov. 3, 2022) (“Joint CCA Opening Comments”).
3 Proposed Decision at 140.
4 R.18-12-006, Opening Comments of San Diego Gas & Electric Company (U 902 M) on Proposed Decision on Transportation Electrification Policy and Investment at 9-10 (Nov. 3, 2022) (“SDG&E Opening Comments”).
2 because the Proposed Decision is clear that LITE pilots must serve both unbundled and bundled customers and treat those customers equally.5 SDG&E also argues that LITE would be “administratively burdensome.”6 In opening comments, the Joint CCAs recommended modifications to the LITE program that would reduce the administrative burden associated with the program and address SDG&E’s concerns. The Joint CCAs reiterate those modifications in these comments and request that the Commission not only approve the program with those modifications, but also increase its dedicated budget. The Joint CCAs also express their support for the Greenlining Institute’s (Greenlining) and GRID Alternatives’ recommended modifications to the LITE program.

I. REPLY COMMENTS
A. SDG&E’s concerns with the LITE pilot program do not merit rejection of the program in its entirety.

SDG&E makes two arguments in support of its recommendation that the Commission reject the LITE pilot program:7 first, that “it is inappropriate to fund CCA programs through distribution rates”; and second, that the LITE program is “administratively burdensome” because it “requir[es] the utility to function as a regulator for the CCAs and serve as the intermediary between CCAs, the Commission, and program administrators.”8 SDG&E’s first argument is based on an inaccurate factual premise. The LITE pilot program is not a “CCA program” as SDG&E suggests; the Proposed Decision requires that LITE pilots, which could also be proposed by community-based organizations (CBOs) and other entities that have expertise in working with their local communities, serve both bundled and unbundled customers, and treat both customers equally.9 It is entirely appropriate for programs serving both bundled and unbundled customers to be funded through distribution rates.

With respect to SDG&E’s second argument, the Joint CCAs agree that the Commission should modify the structure of the LITE pilot program to make it less administratively burdensome and minimize the IOUs’ role as an “intermediary” between the CCAs and the Commission. The Joint CCAs recommended, in opening comments on the Proposed Decision, that the Commission 5 Proposed Decision at 143.
6 SDG&E Opening Comments at 9.
7 Id. at 9-10.
8 Id. at 9.
9 Proposed Decision at 143.
3 clarify that contracts between IOUs and entities submitting winning proposals for the LITE pilot program should be narrowly focused on addressing the mechanics of fund transfers without imposing IOU managerial or supervisory authority over pilot program administrators.10 Further, the Program Handbook should include clear threshold criteria for the purpose of shortlisting projects to submit to the Commission, thereby further minimizing any administrative burden on the IOUs. While SDG&E asserts that the utility would serve as a “regulator for the CCAs” in the LITE pilot program, SDG&E offers no examples or evidentiary support for regulatory duties that would be imposed on the IOUs. On the contrary, under the Proposed Decision, the Commission will review shortlisted projects and approve LITE pilots, and will also manage the Mid-Cycle Assessment Process, which helps ensure that the IOU does not function as a “regulator” for the CCAs.11
Any administrative burden associated with the LITE program, however, is not sufficient reason for the Commission to reject the program in its entirety. As the Proposed Decision observes, the LITE pilot program will enable entities that have expertise in working with their local communities to design innovative programs that best meet the needs of underserved communities.12 Importantly, the Joint CCAs observe that SDG&E was the only commenter to recommend that the Commission reject the LITE program whereas several commenters voiced support for the program.13 The Commission should therefore approve the LITE pilot program.

B. The Joint CCAs support Greenlining’s proposals to increase the budget of the LITE program and to adopt a set of priority selection criteria for the LITE program.

The Greenlining Institute supports the LITE pilot program and—given the program’s propensity to reach low-income community and disadvantaged community (DAC) market segments—asks the Commission to increase the total amount of funding dedicated to the pilot 10 Joint CCA Opening Comments at 9.
11 Proposed Decision at 142.
12 Id.at 140.
13 See R.18-12-006, Opening Comments of the Greenlining Institute on Proposed Decision on Transportation Electrification Policy and Investment at 11 (Nov. 3, 2022) (“Greenlining Opening Comments”) (supporting the LITE program and recommending that the Commission increase the funding dedicated to the program); Comments of the Utility Reform Network on Proposed Decision on Transportation Electrification Policy and Investment at 8 (Nov. 3, 2022) (supporting the LITE program and recommended that the program be retained regardless of other changes made to the FC1 BTM Rebate Program).
4 program.14 Greenlining notes that increased funding can ensure: 1) funding for capacity building and technical assistance for CBOs that do not have “existing resources, systems and infrastructure to be able to manage and implement a pilot program on their own”; and 2) a sustainable funding source for successful pilot projects to scale.15 The Joint CCAs support Greenlining’s proposal. In opening comments on the Proposed Decision, the Joint CCAs recommended that the Commission significantly increase the LITE program’s dedicated budget and observed that more funding would translate to more innovative pilots deployed through the program.16 The Joint CCAs agree with Greenlining that additional dedicated funding would also help ensure that LITE pilots are implemented by a diverse set of entities and have an opportunity to scale.

Greenlining also urges the Commission to develop a set of priority selection criteria for submissions to the LITE pilot program RFP “in order to prioritize applications that have stronger equity components[.]”17 The Joint CCAs support Greenlining’s proposal, and recommend that the selection criteria be proposed and refined through the Program Handbook development process.

The chief purpose of the LITE program is to address the unique needs of underserved customers that the statewide FC1 BTM Rebate Program does not address, and equity selection criteria will help ensure that shortlisted pilots are the ones most likely to meet those needs.

C. The Joint CCAs support GRID’s recommendation that the Commission allow LITE pilot administrators the flexibility to implement pilots that deliver incentives to income-qualified, single-family homes.

GRID Alternatives (GRID) observes that neither the FC1 BTM Rebate Program nor the LITE pilot would allow income-qualified single-family households to receive incentives. GRID recommends that if the Commission does not allow income-qualified single-family households to access FC1 rebates, then at least, the Commission should modify LITE pilot implementation criteria to specifically allow proposals that deliver incentives to income-qualified single-family households to be eligible to participate in the LITE pilot program.18 The Joint CCAs agree that applicants to the LITE program are well-placed to design incentives that best meet the needs of 14 Greenlining Opening Comments at 11.
15 Greenlining Opening Comments at 12.
16 Joint CCA Opening Comments at 6-7 (recommending that the Commission increase the LITE program budget from $25 million to $50 million).
17 Greenlining Opening Comments at 12.
18 R.18-12-006, Opening Comments of Grid Alternatives on the Proposed Decision on Transportation Electrification Policy and Investment at 3 (Nov. 3, 2022). 5 local underserved communities and support flexibility with respect to LITE pilot program incentive design. The Joint CCAs note, however, that the Proposed Decision does not address LITE pilot parameters for single-family households. Therefore, while supportive of GRID’s recommendation, the Joint CCAs would suggest that the Program Handbook address the design parameters that should be required for LITE pilots to be considered for Commission approval.

II. CONCLUSION
For the reasons explained in Joint CCAs’ opening and reply comments, the Joint CCAs continue to recommend the specific changes to the Proposed Decision described in Appendix A to Joint CCAs’ Opening Comments on the Proposed Decision.

Respectfully submitted,
/s/ Nikhil Vijaykar
Nikhil Vijaykar
Sheridan Pauker

KEYES & FOX LLP
580 California St., 12th Floor
San Francisco, CA 94104
Telephone: (408) 621-3256
E-mail: [email protected]
On behalf of Joint Community Choice
Aggregators
Dated: November 8, 2022
Docket: A.22-02-005 et al.

Exhibit Number: Exhibit 4
Date: November 21, 2022
Commissioner: Shiroma
Administrative Law Judge: Kao, Fitch
Witness: Various

MARIN CLEAN ENERGY
REBUTTAL TESTIMONY REGARDING 2024-2031 BUSINESS & PORTFOLIO PLAN AND ADMINISTRATIVE LAW JUDGES’ RULING SEEKING RESPONSES TO

SPECIFIC QUESTIONS IN INTERVENOR TESTIMONY
EXHIBIT 4
1-i

MARIN CLEAN ENERGY
REBUTTAL TESTIMONY REGARDING 2024-2031 BUSINESS & PORTFOLIO PLAN AND ADMINISTRATIVE LAW JUDGES’ RULING SEEKING RESPONSES TO

SPECIFIC QUESTIONS IN INTERVENOR TESTIMONY
EXHIBIT 4

TABLE OF CONTENTS

1. Executive Summary 1

2. Rebuttal Testimony 2

2.1. The Commission Should Authorize MCE’s Commercial Equity Program Budget. (Witness: Joseph Lande) 2

2.2. The Commission Should Authorize MCE’s Workforce Education & Training Program. (Witness: Alice Havenar-Daughton, Jennifer Green) 5

3. Reply to Administrative Law Judges’ Ruling Seeking Responses to Specific Questions in Intervenor Testimony (Witness: Various) 7

4. Conclusion 15
Attachment A: Alice Havenar-Daughton Resume
Attachment B: Joseph Lande Resume
Attachment C: Jennifer Green Resume
Attachment D: Quashaun Vallery Resume
Attachment E: Commercial Equity Program - Request for Proposals 1 1 1. Executive Summary
2 Marin Clean Energy (“MCE”) submits this Rebuttal Testimony to the California Public 3 Utilities Commission (“CPUC” or “Commission”) in support of its Application of Marin Clean 4 Energy for Approval of 20024-2031 Energy Efficiency Business Plan and 2024-2027 Energy Efficiency Portfolio Plan (“MCE’s Application”). 5 1 MCE additionally submits testimony in 6 response to Administrative Law Judges’ Ruling Seeking Responses to Specific Questions in Intervenor Testimony (“Ruling”),2 7 and E-mail Ruling Extending Due Dates for Intervenor Testimony and Rebuttal Testimony.
3 8
9 MCE’s testimony responds to comments from the Public Advocates Office (“Cal 10 Advocates”) on its proposed Commercial Equity and Workforce Education and Training (“WE&T”) programs. 11 4 MCE requests the Commission approve its sufficiently detailed, justified and portfolio compliant programs.5 12 Section 3 of MCE’s testimony responds to Ruling questions 13 on community engagement, external funding including, but not limited to, the Inflation Reduction 14 Act (“IRA”), and the need for continued integration of energy efficiency (“EE”) programs with 15 other distributed energy resource (“DER”) programs. MCE urges the Commission to approve its 16 proposed portfolio of EE programs that will further reduce greenhouse gas emissions, deliver 17 equitable community benefits, provide vital decarbonization focused workforce development, 18 produce energy savings, and offer support to California’s grid reliability. 1 A.22-03-012 submitted March 4th, 2022.
2 Filed August 26th, 2022.
3 Filed September 15th, 2022.
4 See MCE Application, Exhibit 1, pp. 1-3, 1-14, 1-18 - 1-19, 1-26 - 1-27; Exhibit 2, pp. 1-18, 4- 31, A-20.
5 D.21-05-031.
2 1 2. Rebuttal Testimony
2 MCE respectfully requests the Commission approve its proposed Commercial Equity program6 and WE&T program7 3 budgets. MCE submits supplemental facts on its Commercial 4 Equity program to further support Commission approval. Additionally, MCE offers clarifying details on its electrification WE&T program in response to Cal Advocates’ Intervenor Testimony.8 5 6 2.1. The Commission Should Authorize MCE’s Commercial Equity Program 7 Budget. (Witness: Joseph Lande)
8 9 MCE provided sufficient detail, documentation and justification for the approval of its Commercial Equity program in its Application. 10 9 MCE proposed an innovative, and community-11 led program aimed to benefit historically underserved businesses and communities. MCE’s 12 Commercial Equity program focuses on delivering energy savings and non-energy benefits (“NEBs”) to Commercial Equity customers.
10 13 Distinguishable from other PAs’ Equity segment
14 proposals, MCE designed its Commercial Equity program to heavily rely on community engagement strategies for program design, implementation and evaluation. 15 11 MCE designed its 16 community engagement strategies to support the achievement of related recommendations and 17 requirements from the California Energy Efficiency Coordinating Committee (“CAEECC”) 6 MCE Application, Exhibit 2, pp. A-3 - A-5.
7 MCE Application, Exhibit 2, pp. A-6 - A-8.
8 Cal Advocates, Intervenor Testimony, CA-03, p. 1-11.
9 MCE Application, Exhibit 2, pp. 4-28 - 4-34.
10 MCE defines “Commercial Equity customers” for the purposes of its Application as businesses in ESJ communities. See Exhibit 2, Chapter 3, Section 4.2. 11 MCE Application, Exhibit 2, pp. 4-28 - 4-29, 4-31 - 4-32. 3 Hosted Equity Metrics Working Group Report,
12 Decision (“D.”) 21-05-031,13 1 and Environmental
and Social Justice Action Plan (“ESJ Action Plan”)14 Goals 2 and 5. 15 2 The Commission and all
3 parties stand to learn significantly from MCE’s community-led program design and 4 implementation. Hence, the Commission should reject Cal Advocates’ proposal to significantly 5 reduce MCE’s Commercial Equity program budget.
6 Cal Advocates states the Commission should reduce MCE’s Commercial Equity program 7 budget because of the “lack of clear information in the form of a program implementation plan, 8 program card, or budget justifications, the Commission should reduce the Commercial Equity program budget by 30% for years 2024-2025.”16 9 Cal Advocates’ request frustrates the purpose of the Equity segment17 10 by limiting the ability of PAs to value and incorporate community 11 engagement into Equity programs design. MCE’s submittal of a full program implementation plan, 12 CAEECC-Hosted Equity Metrics Working Group, Report and Recommendations to the California Public Utilities Commission and the Energy Efficiency Program Administrators, (October 2021), available at: https://4930400d-24b5-474c-9a16- 0109dd2d06d3.filesusr.com/ugd/849f65_422f2a5a35bb4bcbbabe50e7ecccf6f2.docx?dn=Final% 20EMWG%20Report_10.20.2021.docx, Appendix B (offering recommendations for tracking and promoting PA community engagement activities).
13 D. 21-05-031, pp. 14-15, 22-23.
14 MCE Application, Exhibit 2, pp. A-3 - A-5. ESJ Action Plan, Cal. Pub. Util. Comm’n, Environmental and Social Justice Action Plan version 2.0 (April, 2022), available at:
https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/news-andoutreach/documents/news-office/key-issues/esj/esj-action-plan-v2jw.pdf (“Goal 2: Increase Investment in Clean Energy Resources to Benefit ESJ Communities, Especially to Improve Local Air Quality and Public Health; Goal 5: Enhance Outreach and Public Participation Opportunities for ESJ Communities to Meaningfully Participate in the CPUC’s Decision-Making Process and Benefit from CPUC Programs.”).
15 MCE Application, Exhibit 2, pp. 4-28 - 4-29 (listing ESJ Action Plan Goals 2 and 5 in Commercial Equity program design); MCE Application, Exhibit 2, pp. 1-9 - 1-10 (listing MCE’s commitment to track Equity segment performance with CAEECC equity metrics). 16 Cal Advocates, Intervenor Testimony, CA-02, p. 2-31. 17 D. 21-05-031, pp. 14-15 (listing ESJ Action Plan Goals 2 and 5 in its Equity segment definition).
4 additional program card details and greater zero-based budgeting18 1 at this stage would narrowly 2 constrain the program to a PA-prescribed approach. Requiring this level of detail prior to the 3 opportunity to conduct directed community engagement effectively silences the voices of 4 community-based organizations (“CBOs”) and community residents. An enhanced zero-based 5 budget approach with pre-determined budget categories would wastefully discourage innovative 6 proposals from vendors, limits potentially beneficial competition between vendors, and curbs the 7 integration of information gathered through community engagement partnerships with CBOs. Cal 8 Advocates budget reduction request prematurely and unjustifiably limits the number of 9 Commercial Equity customers MCE may serve and the benefits they may receive. 10 After filing its Application, MCE completed a competitive solicitation for the Commercial Equity program and submits additional facts from that process to the record of this proceeding.19 11 12 The purpose of the Commercial Equity program, as further defined in the Request for Proposals 13 (“RFP”), includes:
14 • “Filling gaps in services that are not currently provided by other MCE programs; 15 • Providing solutions or services that compliment or leverage existing programs in 16 MCE’s service area;
17 • Sustained energy efficiency benefits, as well as those focused during the summer 18 peak period of 4-9pm June - September.
19 • Creating value through behavioral modification or non-capital measures 20 • Providing on-going technical support, commissioning, and training; 21 • Reduced or no copays.
22 • Providing targeted marketing and direct networking within communities to reach 23 Equity Commercial Customers; and
24 • Focusing on Non-Energy Benefits (“NEBs”), including a methodology to quantify its value.” 20 25
18 Cal Advocates, Intervenor Testimony, CA-02, pp. 2-31- 2-32. 19 See Attachment E, Commercial Equity Program – Request for Proposals. 20 Id., pp. 2-3.
5 The RFP lists the known barriers21 1 Commercial Equity customers face accessing EE 2 programs including, but not limited to, language barriers, EE programs’ historic focus on larger 3 and different commercial customers, and issues identified by the California Energy Commissions in its SB 350 Low-Income Barriers Study – Part A. 4 22 MCE also outlines the scope of work for the 5 implementation partner of the Commercial Equity program which includes specific community 6 engagement requirements for program development, program implementation plan development 7 requirements, program performance metrics including NEBs, and measurement and verification (“M&V”) requirements. 8 23 MCE requested detailed pricing for all services provided and annual program budgets.24 9
10 MCE received five competitively solicited proposals from implementers on its RFP, 11 interviewed three potential implementers, and is actively engaged in contract negotiations with a 12 finalist for the Commercial Equity program. Following the finalization of the implementation 13 contract, MCE plans to conduct a program implementation plan webinar to solicit and integrate 14 stakeholder feedback. Following the webinar, MCE will file an Implementation Plan consistent with portfolio rules for new programs. 15 25 MCE requests the Commission approve its Commercial 16 Equity program budget.
17 2.2. The Commission Should Authorize MCE’s Workforce Education & Training 18 Program. (Witness: Alice Havenar-Daughton, Jennifer Green) 19 MCE justified its WE&T program scope and costs in its Application per the requirements of D.21-05-031.26 20 The Commission should approve MCE’s requested WE&T budget. Cal 21 Id., p. 3.
22 California Energy Commission, SB 350 Low-Income Barriers Study – Part A (2016), available at: https://efiling.energy.ca.gov/getdocument.aspx?tn=214830. 23 Attachment E, Commercial Equity Program – Request for Proposals, pp. 3-4. 24 Id., pp. 5-6.
25 D.21-05-031, p. 31 (detailing implementation plan requirements for the portfolio process and citing D.15-10-028).
26 See e.g. MCE Application, Exhibit 2, pp. 2-11, 3-15, 4-1, 4-34 - 4-41. 6 1 Advocates requests the Commission significantly reduce MCE’s proposed WE&T budget “to 2 avoid redundancy with the newly created [statewide] SW WE&Ts programs run by the [investor-owned utilities] IOUs.” 3 27 MCE rejects this recommendation for the following reasons: First, 4 MCE’s WE&T program offers a unique and critical electrification focus distinct from statewide WE&T programs. 5 28 MCE’s electrification WE&T program is essential to supporting the 6 decarbonization goals of the Commission including its Staff Proposal for Gas Energy Efficiency Incentives and Codes and Standards Sub-Programs and Budgets. 29 7 Second, MCE is committed to
coordinating with the IOUs to avoid duplication and redundancy with the SW WE&T programs. 30 8
9 Third, MCE appropriately scaled its scope of work and proposed budget to meet the needs of the growing electrification market.
31 10 Fourth, local WE&T programs add the unique value of local relationships and knowledge that cannot be replicated at the statewide level.32 11 27 Cal Advocates, Intervenor Testimony, CA-03, p. 1-11. 28 MCE Application, pp. 11-12, 14. MCE Application, Exhibit 2, pp. 1-4 - 1-5, 1-8 - 1-9, 2-2; Chapter 4, Section 6; A-6.
29 Filed August 2nd, 2022, in A.22-02-005 et al.
30 MCE Application, Exhibit 1, pp. 1-35 - 1-36; MCE Application, Exhibit 2, pp. 3-19, 4-40 - 4- 41(detailing continued coordination efforts between MCE and PG&E on WE&T programs); MCE 2021 Energy Efficiency Annual Report, available at: https://www.mcecleanenergy.org/wp-content/uploads/2022/06/MCE-2021-Energy-Efficiency-Report_06012022.pdf, Attachment B:

MCE & PG&E Joint Cooperation Memorandum for Program Year 2023, pp. 1-3 (“To coordinate on the implementation of MCE’s and PG&E’s WE&T programs, PG&E will provide its list of trainings to MCE on a quarterly basis, and MCE will provide a similar list to PG&E. The goal of coordination between MCE’s and PG&E’s WE&T programs is to ensure that ratepayer funds deliver resources efficiently and effectively across the shared territories and leverage each other’s resources and materials when appropriate to avoid duplication.”). 31 MCE Application, Exhibit 2, Chapter 4, Attachment B - FINDINGS OF MCE ROUNDTABLES FOR WE&T PROGRAM; MCE Application, Exhibit 2, p. 2-11 (“MCE developed an implementation budget for this program based on a time and materials rate for a determined scope of work. Rates were established through a competitive solicitation process.”). 32 Id. (outlining specific local workforce challenges, needs and opportunities in MCE’s unique service area); MCE Application, Exhibit 2, p. 3-15 (detailing MCE’s partnership and engagement with local and regional workforce development partners). 7 1 The Commission should deny Cal Advocates’ request to limit MCE’s WE&T program. 2 MCE correspondingly requests the Commission approve its proposed WE&T program budget. 3 3. Reply to Administrative Law Judges’ Ruling Seeking Responses to Specific Questions 4 in Intervenor Testimony (Witness: Alice Havenar-Daughton, Jennifer Green, Joseph 5 Lande, Quashaun Vallery)
6 7 1. Equity and Advancement of the Environmental and Social Justice Action Plan (Issue 7) 8 9 1. Should community engagement be tracked and reported by the program administrators 10 as an indicator, or should it remain as a principle guiding equity programs? Please 11 explain your reasoning? (Witness: Quashaun Vallery)
12 13 MCE supports meaningful community engagement in guiding all EE portfolio programs, 14 and especially Equity programs. MCE worked to thoroughly integrate community engagement as a key strategy and guiding principle for its Equity programs. 15 33 MCE fears if the Commission 16 arbitrarily assigns specific community engagement indicators on behalf of ESJ communities in a 17 top-down manner, it will unintentionally limit the quality and potential effects of corresponding 18 community engagement activities. MCE can imagine PAs satisfying community engagement 19 indicator requirements without meaningfully engaging and incorporating ESJ community 20 feedback. MCE discourages the Commission from independently designing a community 21 engagement box for PAs to check that wasn’t designed and advocated for by ESJ communities and 22 CBOs. ESJ communities face many barriers to participating in CPUC programs and are the experts 23 on their solutions. Community engagement requirements must specifically respond to these 24 barriers and permit community participants to meet their goals through participation. The number 25 of engagement activities completed, for example, does not provide the Commission with an 26 accurate picture of the quality of a PA’s engagement efforts and their influence on program design, 27 implementation and evaluation.
33 MCE Application, Exhibit 2, pp. 3-24, 3-30, 4-32.
8 1 MCE proposes that community engagement remain a guiding principle and PAs establish 2 specific engagement processes in partnership with the communities they serve. MCE proposes 3 PAs work with ESJ communities and CBOs to propose community engagement frameworks in 4 their true-up or mid-cycle advice letters. MCE suggests the community engagement frameworks 5 should include, but are not limited to, the following elements:
6 • Benefit to Communities: Detailing how PAs will compensate communities for their 7 expertise, time and efforts to participate in the decision-making processes and programs. 8 Detailing how these services support and align with the CBOs’ existing mission and goals. 9 • Language Access: Detailing how PAs will improve engagement materials and activities 10 for the most spoken languages in their service area? 11 • Feedback: Detailing how PAs will consider, integrate and respond to feedback from 12 communities.
13 • Continuous Improvement: Detailing how PAs plan to continue developing their 14 understanding of barriers to participation and take the necessary actions to address these 15 barriers.
16 • Training: Detailing how PAs plan to address systemic barriers to participation in the 17 decision-making process.
18 • Outreach: Listing and describing the CBOs that the PAs engaged, as well as the activities 19 to engage them.

MCE recommends the Commission ask the Disadvantaged Communities Advisory Group34 20 21 (“DACAG”) for more detailed recommendations on ESJ focused community engagement 34 CPUC, Disadvantaged Communities Advisory Group, available at:
https://www.cpuc.ca.gov/dacag/.
9 1 frameworks elements. Finally, MCE recommends that PAs report progress on their community 2 engagement frameworks in their annual EE reports. Reporting on progress provides an important 3 accountability mechanism to PAs’ community engagement efforts and allows all interested 4 stakeholders to benefit from lessons learned.
5 2. Flexibility and Opportunity for Innovation (Issue 8) 6 7 1. As discussed in the Environmental and Social Justice (ESJ) Action Plan, the CPUC is 8 interested in engaging communities to improve design, delivery, adoption, and innovation 9 of energy efficiency solutions. This engagement and innovation could be accomplished 10 through “community-based program design”, which is original energy efficiency program 11 design ideas coming directly from, or being led by, community/stakeholders, rather than 12 communities offering feedback/input on proposed program administrator-based (or third 13 party) program designs. (Witness: Alice Havenar-Daughton, Jennifer Green) 14 15 a. Should the CPUC require “community-based program design” in the program 16 administrators’ portfolios? If so, please describe this suggested requirement in 17 detail including how and to which program administrators, and to which portion 18 of the portfolio should this requirement apply (e.g., a segment, a program 19 administrator’s program(s) already proposed, a new proposed program not in 20 program administrators’ applications, other).
21 22 MCE supports community-based and community-led program design, implementation and 23 evaluation of EE programs. MCE worked intentionally to incorporate meaningful community engagement throughout its Application. 24 35 MCE supports community leadership of EE programs 25 across the portfolios and especially in the Equity segment. 26 However, without additional outreach to ESJ communities and CBOs on record in this 27 proceeding, MCE fears of potential unintended consequences from imposing a community-based 28 program design requirement at this stage. The Commission may end up shifting many of the 29 administrative, capacity and financial burdens of EE program administration unfairly to CBOs 35 See e.g. MCE Application, Exhibit 2, p. 34.
10 1 who may have other interests and or capacity constraints. The landscape of CBOs, the activities 2 they engage in, their resources, and the missions they serve are extremely diverse. 3 The Commission would benefit from additional CBO guidance on how to best support 4 community leadership in EE programs before establishing this requirement. For example, the 5 Commission ordered a CBO Pilot Working Group in the proceeding to address energy utility 6 customer bill debt accumulated during the COVID-19 Pandemic to explore best practices to support CBO leadership in programs. 7 36 MCE supports exploring this concept further through 8 additional CPUC facilitated workshops, outreach to CAEECC, and guidance from the DACAG. 9 b. What do you propose the CPUC do to encourage or direct program administrators 10 or a third party administrator to ensure energy efficiency portfolios include 11 community-based programs designed (and/or implemented) by and for 12 communities? For example, should the CPUC direct the program administrators 13 to procure a new statewide program that recruits, selects, and funds community-14 based proposals? (e.g., one that offers a simple solicitation structure uniquely 15 designed for communities to respond with concept papers)? If so, what guidance 16 should the CPUC provide to facilitate development of criteria by which to evaluate 17 proposals?
18 19 As stated in our previous response to Question 1. (a)., MCE supports community-based 20 program design and implementation. MCE supports the concept of directing PAs to include 21 community-based programs designed or implemented by communities. MCE urges the 22 Commission to explore this concept further through CPUC facilitated workshops, directed 23 outreach to ESJ communities and CBOs, outreach to CAEECC for additional input, and guidance 24 from the DACAG prior to establishing a requirement. EE program administration requires 25 navigating a resource intensive and complex regulatory landscape. The Commission must make 26 all rules and regulations clear, and publicly available in a straightforward fashion. The Commission 36 D.22-04-037, pp. 18-19 (explaining CBO partnerships are essential to serving ESJ communities and noting information gaps in the Commission’s knowledge of existing CBO networks and activities.).
11 1 should also consider appropriately streamlining the administrative processes and reducing the 2 administrative burdens of EE program administration to support community-based proposals. 3 3. Aligning With External Funding (Issue 12)
4 1. Should it be mandatory for third-party implementers and the lead investor-owned utilities (IOU) 5 to report external match funding and coordination? Do you have suggestions for how they would 6 report back, to whom, and with what regularity? (Witness: Alice Havenar-Daughton, Jennifer 7 Green)
8 9 Should the Commission pursue external match funding and coordination requirements, 10 MCE recommends PAs include a section in their EE annual reports. MCE discourages the 11 Commission from requiring detailed reporting at the measure level as it would be extremely 12 administratively burdensome, and in some cases impossible to accomplish. 13 3. What mechanism(s) should program administrators use to update plans and forecasts for 2024 14 and beyond, based on new initiatives included in the IRA? Is the True-Up Advice Letter due on 15 September 1, 2023 a sufficient mechanism for program administrators to incorporate IRA 16 assumptions into their planning, or are additional steps needed? (Witness: Alice Havenar-17 Daughton, Jennifer Green) 18 19 MCE agrees that the True-Up Advice Letter due September 1, 2023, is an appropriate 20 mechanism for program administrators to begin incorporating information related to the Inflation 21 Reduction Act (“IRA”). However, it’s extremely unlikely many funds within the IRA will be 22 received by potential applicants, including EE PAs, prior to that deadline. Many funds within the 23 IRA require both federal and state rulemaking processes with discretionary timelines before a competitive solicitation process of unknown length. 24 37 Many IRA federal rulemaking processes have not formally begun at the date of this filing.38 25 Hence, it is difficult to predict with any degree 37 See e.g. H.R. 5376 sec. 50121 Home Energy Performance-Based, Whole-House Rebates (HOMES Rebate Program).
38 Department of Energy, Biden-Harris Administration Announces State And Tribe Allocations For Home Energy Rebate Program, (November 2, 2022), available at:
https://www.energy.gov/articles/biden-harris-administration-announces-state-and-tribe-allocations-home-energy-rebate ( “From November through January, DOE will hold a series of 12 1 of certainty the precise timelines, eligibility requirements and coordination steps required to 2 successfully layer IRA funds into EE portfolio programs. Once details from the IRA rulemakings 3 are available, PAs need time to analyze eligible customers and measures, budgets, administration 4 timeframes, and reporting requirements. MCE is actively researching and tracking IRA 5 implementation activities at the federal and state levels to incorporate funds into EE portfolio 6 programs. MCE will communicate with the Commission in an ongoing fashion about the need for 7 potential policy changes required as more information becomes available. 8 For these reasons, MCE recommends the Commission permit additional communication 9 and policy requests on the IRA following the September 1, 2023, True-Up Advice Letter filing. 10 Successfully integrating and maximizing the potential benefits of the IRA funding to ratepayers 11 and EE programs will require ongoing communication between the Commission, the California 12 Energy Commission, PAs and parties. The information required to establish a precise timeline for 13 PAs integration efforts is not presently available.
14 4. Energy Efficiency Integrated Programs (Issue 14)
15 16 1. In the context of IDSM being largely limited to EE/DR integration historically, do you agree 17 with Pacific Gas and Electric Company’s (PG&E) proposal in their Business Plan to 18 “update…IDSM rules to support comprehensive load management and enable greater program 19 integration” by allowing “a mechanism for [program administrators] to propose, and for the 20 Commission to delegate to its staff to assess on a case-by-case basis, programs that integrate 21 demand-side management approaches including [energy efficiency], demand response (DR), 22 distributed generation, managed electric vehicle charging, and time-varying or dynamic 23 pricing”? Why or why not? (Witness: Joseph Lande)
24 25 MCE supports PG&E’s recommendation to update integrated demand-side management 26 (“IDSM”) rules to allow greater integration of EE and other distributed energy resource (“DER”) listening sessions to engage a wide array of stakeholders, including direct engagement with states and Tribes, labor, industry, and others, on these consumer rebate programs. Following the listening sessions, DOE will issue a Request for Information for public input in early 2023.”); The Department of Treasury began soliciting public input on Clean Energy Tax Incentives on October 5, 2022, available at: https://home.treasury.gov/news/press-releases/jy0993. 13 1 programs. MCE agrees with PG&E that the IDSM program approved by D.18-05-041 unnecessarily limits how and which EE interventions may couple with DR. 2 39 MCE supports 3 PG&E’s recommendation to allow PAs to propose any DER intervention under the IDSM program 4 that they judge reasonable. This recommendation, for example, permits the beneficial combination 5 of EE measures with an energy storage resource and a combined participation in a behavioral 6 demand response (‘DR”) activity. A similar beneficial relationship can be envisioned for electric 7 vehicles (“EVs”) in place of, or in addition to, the energy storage resource. 8 2. One possible option for enabling more IDSM in energy efficiency programs could involve 9 using several separate funding streams (i.e., energy efficiency, IDSM, DR, the Self-10 Generation Incentive Program for battery storage, etc.) within a single energy efficiency 11 program, with program administrators maintaining separate accounting to allow for 12 clear delineation of the use of each funding source and associated savings by technology 13 category while allowing for a more seamless flow of energy efficiency and IDSM funds to 14 implementers and/or customers. (Witness: Joseph Lande) 15 16 Please provide your recommendations for:
17 18 a. Whether you believe this type of approach is worthy of consideration by the 19 Commission.
20 21 Yes, MCE supports the Commission exploring all methods to enable greater integration 22 of IDSM in EE with several DR, Self-Generation Incentive Program (“SGIP”) and related 23 funding streams.
24 b. How the Commission could efficiently approve funding for this approach. 25 MCE supports PG&E’s proposed Advice Letter process to efficiently approve funding. 26 d. Double-counting considerations to ensure ratepayer dollars are not paying twice for the 27 same resource.
28 29 Future IDSM programs could leverage, and build upon, existing double counting 30 prevention processes developed between the different EE PAs. MCE currently establishes double-39 D.18-05-041, pp. 36-38. 14 1 counting protocols with PG&E and Bay Area Regional Energy Network (“BayREN”) within its 2 Joint Cooperation Memoranda (“JCMs”). PAs could develop a similar cooperation memo with the 3 SGIP administrators, for example. Double counting prevention plans could also be included in the 4 funding request Advice Letter and the program Implementation Plan. 5 e. What types of distributed energy resources (DER) should be considered for inclusion? 6 MCE supports including all behind-the-meter or customer-sited DER resources. MCE does 7 not see any present need for the Commission to limit any types of DERs. The Commission should 8 ground deeper integration between IDSM projects and EE in customers’ diverse needs and 9 interests. Integrated programs must reflect an openness to a wide range of technologies rather than 10 pre-determining ideal or viable solutions.
11 f. Other requirements or considerations.
12 To facilitate the incorporation and valuation of DER resources under the EE evaluation 13 framework, the Commission should consider a reference standard akin to an EE workpaper for 14 DER resources. For example, the Commission should establish performance requirements and an 15 Expected Useful Life (“EUL”) for energy storage resources based on battery specifications, which 16 would allow for a Total Systems Benefit (“TSB”) based incentive structure. The Commission 17 should further combine a TSB incentive structure with performance incentives or “kicker” 18 payments to ensure the discharge of batteries during periods of significant grid stress. Moving 19 towards a TSB valuation of battery storage would allow for better valuation of energy storage 20 resources under the EE paradigm and unlock the opportunity for closer integration between EE 21 and DER programs and resources.
22 MCE additionally recommends all PAs, including community choice aggregators 23 (“CCAs”) and non-IOU PAs, may access IDSM funding.
15 1 4. Conclusion
2 The Commission should approve MCE’s reasonable Commercial Equity program budget 3 and reasonable WE&T program budget. MCE thanks the Commission, Commissioner Shiroma 4 and Administrative Law Judge Kao and Administrative Law Judge Fitch for the opportunity to 5 submit rebuttal testimony and respond to Ruling questions. MCE looks forward to working with 6 the Commission and all parties on supporting the continued evolution of customer-beneficial and 7 community-supported EE programming.

A-1

MARIN CLEAN ENERGY
REBUTTAL TESTIMONY REGARDING 2024-2031 BUSINESS & PORTFOLIO PLAN AND ADMINISTRATIVE LAW JUDGES’ RULING SEEKING RESPONSES TO

SPECIFIC QUESTIONS IN INTERVENOR TESTIMONY
EXHIBIT 4

ATTACHMENT A

ALICE HAVENAR-DAUGHTON RESUME
A-2
Alice Havenar-Daughton
Director of Customer Programs, MCE
1125 Tamalpais Ave, San Rafael, 94901

RELEVANT SKILLS AND EXPERIENCE
● Strong background in energy efficiency, with experience in program design, implementation, and evaluation.
● Oversees implementation of energy programs with over $10 million annually in the Marin Clean Energy service territory.
● Oversaw program launch of MCE’s first low-income multifamily energy efficiency program, the Low-Income Family and Tenants (LIFT) Pilot Program.

EDUCATION
American University, Washington DC, 2010
M.A. Natural Resources and Sustainable Development
McGill University, Montreal, Canada, 2005
B.SC. Architecture

WORK EXPERIENCE

MCE San Rafael, CA, May 2018 – Present
Director of Customer Programs
● Oversees MCE’s portfolio of customer programs, including energy efficiency, transportation electrification, low-income solar. ● Represents MCE externally in stakeholder forums such as California Energy Efficiency Coordinating Committee (CAEECC) and CalTF, and through speaking engagements. ● Lead the development of a new program data tracking tool for program performance and streamline reporting.

MCE San Rafael, CA, June 2017 – April 2018
Manager of Policy and Planning, Customer Programs
● Oversees planning for Demand Side Resource Pilot Programs, including, electric vehicles, fuel switching and low-income solar. ● Works collaboratively with MCE’s Regulatory Team to develop the strategy for MCE’s engagement with the California Public Utilities Commission (CPUC) in the Business Plan Application process, including developing content for filings, drafting talking points, engaging with partners and 1 serving as MCE’s representative to the CAEECC.
● Manages MCE’s EM&V budget for Energy Efficiency Programs and LIFT. ● Oversees all Energy Efficiency and LIFT program reporting to the CPUC. ● Manages MCE’s SF Seasonal Savings Program, the California Energy Commission (CEC) BEO Grant and grant compliance for the electric vehicle charges owned by MCE.

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MCE San Rafael, CA, October 2015 – June 2017
Energy Efficiency Program Manager
● Managed MCE’s Single-Family Energy Efficiency Program. ● Managed all energy efficiency programs reporting to the California Public Utilities Commission.
● Supported MCE’s Business Plan Application through sector chapter development, managing cost effectiveness work done by consultants and leading the internal program logic model and metrics development.
● Represented MCE through engagement and comments on several CPUC-funded EM&V studies of MCE’s programs.

MCE San Rafael, CA, July 2014 – October 2015
Energy Efficiency Specialist
● Developed tracking systems for MCE’s Energy Efficiency program expenditures and savings.
● Represented MCE at the Reporting Program Coordination Group at the CPUC. ● Tracked data and prepared monthly, quarterly and annual reports for the CPUC. Provided data necessary for other compliance requirements.

Opinion Dynamics Corporation Oakland, CA, November 2010 – July 2015 Senior Analyst
● Served as a lead analyst on process and impact evaluations of energy efficiency and demand response programs in California and across the county.

Alliance for Climate Protection Washington, DC, May 2010 – September 2010 Solutions/Policy Team Fellowship
● Analyzed national climate and energy legislation to support renewable energy advocacy effort.

American Council for an Energy Efficient Economy (ACEEE) Washington, DC, January 2010 – April 2010
Buildings Team Intern
● Conducted research on barriers to energy efficiency in building codes.

Energetica Cochabamba, Bolivia, August 2008 – May 2009
Research Assistant
● Conducted a study on the potential for solar water heaters in urban areas of Bolivia which supported the initiation of a new solar water heater project, Proyecto ElSol. ● Assisted in rural educational workshops for subsidized solar panel recipients.

A-4

MARIN CLEAN ENERGY
REBUTTAL TESTIMONY REGARDING 2024-2031 BUSINESS & PORTFOLIO PLAN AND ADMINISTRATIVE LAW JUDGES’ RULING SEEKING RESPONSES TO

SPECIFIC QUESTIONS IN INTERVENOR TESTIMONY
EXHIBIT 4

ATTACHMENT B

JOSEPH LANDE RESUME
A-5
Joseph Lande
Manager of Customer Programs, MCE
1125 Tamalpais Ave. San Rafael, CA 94901

RELEVANT SKILLS AND EXPERIENCE
● 14 years of experience in the design and implementation of ratepayer funded energy efficiency programs, sustainability initiatives and emissions reduction strategies. ● Technical strengths in energy efficiency technologies, energy project analyses, and clean energy policy. Management strengths in project finance, program management, stakeholder coordination and communications.

EDUCATION
Central European University/The University of Manchester, Budapest, Hungary, 2006 Master of Science, Environmental Science and Policy
University of California Santa Cruz, Santa Cruz, USA, 2004 Bachelor of Arts, Environmental Studies

WORK EXPERIENCE
MCE San Rafael, CA, 2017– Present
Manager of Customer Programs
● Program design and oversight of MCE’s non-residential energy efficiency portfolio, serving the Commercial, Industrial and Agricultural sectors. ● Program design and oversight of MCE’s Marketplace programs - including the Peak FLEXmarket and the Commercial Efficiency Market.
● Management of MCE’s non-residential energy efficiency and Marketplace teams.

First Climate Frankfurt am Main, Germany, 2015 – 2017
Portfolio Manager
● Development of sustainability and renewable energy procurement strategies, leveraging renewable energy certificates, carbon offsets, green tariffs, etc. ● Lead role in international business development, proposals and contract management. ● Management of an international portfolio of emissions reduction and sustainability projects.
● Corporate and institutional training sessions on sustainability and climate change. ● Market research on the direction of the global renewable energy and carbon markets.

A-6
Energy Solutions Oakland, CA, 2007 – 2014
Project Manager
● Energy efficiency program design, implementation and assessment for California investor-owned utilities and local government agencies. ● Technical manager and agency manager (customer manager) for the California Energy Commission’s Energy Technology Assistance Program.
● Program Manager serving the Pacific Gas & Electric Company (PG&E) Commercial Water Heater Distributor Program.
● Lighting engineering consultant for the Southern California Regional Energy Network’s public sector program – supporting energy efficiency upgrades in mechanical equipment, lighting, and advanced building controls.
● Project finance expertise covering energy incentive programs, utility and government loan programs, and grant funding.
● Team specialist on California’s Title 24 Building Energy Efficiency Standards. ● Project manager within the PG&E LED Accelerator Program, the Emerging Technologies Program and the Upstream HVAC Program.
● Business development, securing new contracts for projects and programs, leveraging industry relationships, technical expertise, and feasibility assessments. ● Program implementer of the NV Energy HVAC and Motor Distributor Programs. ● Design and implementation of a large-scale energy efficiency monitoring project, targeting multi-level LED fixtures and advanced wireless controls systems installed at local government facilities, under the statewide Energy Technology Assistance Program. ● Specification and auditing support to utility incentive programs, including the PG&E New Efficiency Options Program and the PG&E Non-Residential New Construction Program. ● Project management under the Association of Bay Area Governments Energy Watch Program.
● Management of a regional outreach effort targeting California certified electrical contractors to analyze the impact of utility funded energy efficiency programs.

Environmental and Energy Study Institute Washington DC, 2005 Intern
● Reports, white papers and fact sheets on energy and climate policy developments.

A-7

MARIN CLEAN ENERGY
REBUTTAL TESTIMONY REGARDING 2024-2031 BUSINESS & PORTFOLIO PLAN AND ADMINISTRATIVE LAW JUDGES’ RULING SEEKING RESPONSES TO

SPECIFIC QUESTIONS IN INTERVENOR TESTIMONY
EXHIBIT 4

ATTACHMENT C

JENNIFER GREEN RESUME
A-8
Jennifer Green
Manager of Customer Programs, MCE
1125 Tamalpais Ave. San Rafael, CA 94901

RELEVANT SKILLS AND EXPERIENCE
● 18 years experience with California energy efficiency policy, regulatory, legislative environment; energy program design, execution, and evaluation; government program design, implementation and reporting.
● Management of MCE’s residential and Workforce Education & Training energy efficiency and decarbonization program design, implementation, and reporting. ● Strong commitment to and experience with diversity, equity and inclusion in MCE residential programs and workforce development initiatives. ● Developed and managed municipal energy programs for the City of San Diego. ● Originated and managed a multi-year, multi-partner contract that resulted in: 200+ in-home water and energy consumption assessments.

EDUCATION
San Diego State University, San Diego, CA, 2008, Master of Arts, Public Policy and Political Science
California State University, Sacramento, 1993, Bachelor of Arts, Journalism Building Performance Institute, New York, 2015, Building Analyst and Envelope Certification

WORK EXPERIENCE
MCE San Rafael, CA, 09/2019 – Present
Manager of Customer Program
● Program design and management of MCE’s residential energy efficiency, WE&T and decarbonization portfolio implementation, serving multifamily and single family residential sectors and energy industry workforce.
● Management of MCE’s residential energy efficiency equity and general market teams, including California Public Utilities Commission (CPUC) and MCE-ratepayer funded programs.

Center for Sustainable Energy (CSE) 2005-2013, 2016-2018 Senior Manager, Distributed Energy Resources
● Led and executed municipal contract projects for California jurisdictions to enact climate change goals, including development, implementation and evaluation of:
o Program and project proposals, negotiations, and contract management; o Detailed program budgets and true-ups from program inception to evaluation; A-9
o Reporting to CPUC, California Energy Commission, municipal and regional governments.
● Developed and managed proposals for distributed generation, renewables, and energy efficiency programs, including outreach and education, technical skills and quality assurance with local and state industry and municipal partners. ● Built municipal partnerships, staff support for commercial real estate construction, and contractor industry-focused municipal working groups.
● Fostered external energy policy, regulatory, and business partnerships. ● Presented to local, state, regional, business, utility audiences on energy demand side management, distributed generation, and policy/regulatory issues.

Policy and Legislative Manager
● Formulated organizational position documents on renewables, distributed generation, and energy efficiency programs for state and local decision-makers. ● Fostered relationships and collaborations with local and state governments, renewables, distributed generation, and demand side management.
● Developed energy legislative and policy forums with local and statewide elected officials. ● Staffed a regional energy working group with business, advocacy and municipal members.

Gammage and Green, LLC 2014-2016
Owner, Home Energy Rating Service (HERS) Rater
● Developed and managed all financial, marketing, client procurement and engagement, and sustainability efforts for emerging HERS rater company. ● Presented Building Performance Institute rater training curriculum to contractor industry professionals.
● Provided technical support to contractors to ensure compliance with California building standards.
● Performed over 300 HERS verifications.

San Diego Regional Chamber of Commerce 2004-2005
Policy Manager
● Managed regional energy policy, transportation and small business advocacy committees consisting of leading businesses, advocacy groups, and municipal members in San Diego’s regional business organization.
● Provided analysis to internal/external audiences on energy, transportation, and small business issues.

San Diego State University 2001-2004
International Admissions Manager
A-10

MARIN CLEAN ENERGY
REBUTTAL TESTIMONY REGARDING 2024-2031 BUSINESS & PORTFOLIO PLAN AND ADMINISTRATIVE LAW JUDGES’ RULING SEEKING RESPONSES TO

SPECIFIC QUESTIONS IN INTERVENOR TESTIMONY
EXHIBIT 4

ATTACHMENT D

QUASHAUN VALLERY RESUME
A-11
Quashaun Vallery
Senior Regulatory and Reporting Manager, MCE
1125 Tamalpais Ave. San Rafael, CA 94901

RELEVANT SKILLS AND EXPERIENCE
● Progressive experience in water and energy efficiency programs. ● Cost-effectiveness Analysis.
● Reporting and Regulatory Compliance.
● Data Analysis and Management.
● Quality Assurance and Control.

EDUCATION
University of California, Santa Barbara 2015
Bachelor of Arts in Environmental Studies

WORK EXPERIENCE
MCE San Rafael, CA, 2018 – Present
Senior Regulatory & Reporting Manager
Regulatory & Reporting Manager
Customer Programs Specialist
● Manage regulatory compliance filings and reporting of MCE’s portfolio of energy efficiency programs.
● Work collaboratively with MCE’s Legal and Policy department by providing regulatory and policy analysis, developing content for filings, supporting the development of policy recommendations, and determining impacts of potential policy on MCE’s energy efficiency programs.
● Manage MCE’s Evaluation, Measurement & Verification budget including development, management, and coordination of program evaluation studies. ● Represent MCE at the Reporting Program Coordination Group (PCG) at the California Public Utilities Commission (CPUC).

Frontier Energy Oakland, CA, 2015 – 2018
Present Senior Program Coordinator
Program Coordinator
● Provided regulatory and reporting services to ensure clients’ compliance with the CPUC’s regulatory reporting requirements.
● Supported clients in securing energy efficiency funding through the support of regulatory filings, including cost-effectiveness analysis.

A-12
● Reported energy savings on behalf of clients administering energy efficiency programs; Streamlined reporting processes by developing reporting procedures and automation.
● Represented clients at the Reporting Program Coordination Group (PCG) at the CPUC.

Santa Clarita Water Division - Santa Clarita, CA 2014 - 2015 Conservation Technician - Temporary
● Implemented programs to meet the company’s water efficiency goals, optimize delivery, and improve the effectiveness of the programs to customers. ● Improved marketing and outreach efforts utilizing Constant Contact. ● Streamlined rebate processing for water conservation programs. ● Analyzed water production and consumption data to evaluate the effectiveness of water conservation efforts.
● Developed a water enforcement process to comply with the State Water Resources Control Board (SWRCB) conservation regulations.

A-13

MARIN CLEAN ENERGY
REBUTTAL TESTIMONY REGARDING 2024-2031 BUSINESS & PORTFOLIO PLAN AND ADMINISTRATIVE LAW JUDGES’ RULING SEEKING RESPONSES TO

SPECIFIC QUESTIONS IN INTERVENOR TESTIMONY
EXHIBIT 4

ATTACHMENT E
COMMERCIAL EQUITY PROGRAM – REQUEST FOR PROPOSALS
MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 1 Request for Proposals (“RFP”)
MCE Commercial Equity Program
August 29, 2022

Marin Clean Energy (“MCE”), a California Joint Powers Authority, seeks a qualified organization that can provide innovative design, administration and management of the proposed MCE Commercial Equity Program (“Program”).

I. ABOUT MCE
MCE is a not-for-profit, public agency that has been setting the standard for clean energy in California since 2010. MCE offers 60% renewable power at stable rates, significantly reducing greenhouse emissions and reinvesting millions in local programs. Serving a 1,200 MW peak load, MCE provides electricity service and innovative programs to more than 575,000 customer accounts and 1.5 million residents and businesses in 37 communities across four Bay Area counties: Contra Costa, Marin, Napa, and Solano.

II. BACKGROUND
Equity is a driving force behind program development at MCE, and will remain a key objective in the future. One of the defining characteristics of MCE’s four-county service area is diversity:
in financials, backgrounds, and languages. The goal of the Program is to help ensure that MCE’s diverse commercial customers have access to the benefits of energy efficiency (“EE”).

The Program will serve MCE’s “Equity Commercial Customers,” the definition of which stems from the California Public Utilities Commission’s (“CPUC”) definition of “Environmental and Social Justice Communities”, which can be found in the CPUC Environmental and Social Justice (“ESJ”) Action Plan.
1 There are three criteria for Equity Commercial Customers to be eligible for the Program (“Criteria”); Equity Commercial Customers must exist in:
2 • Disadvantaged Communities, defined as census tracts that score in the top 25% of the most current CalEnviroScreen,
3 along with those that score within the highest 5% of
CalEnviroScreen Pollution Burden but do not receive an overall CalEnviroScreen score; and
• All tribal lands;
4 and
• Low-income census tracts.

MCE serves approximately 66,000 commercial customers, as well as an additional 4,000 non-residential customers that have no further secondary segment classification per the North American Industry Classification System (NAICS) codes. MCE’s commercial sector consumes an 1 D.21-05-031, p. 14; see Commission’s Draft ESJ Action Plan version 2.0 (Oct. 2021), available at:
https://www.cpuc.ca.gov/esjactionplan/.
2 Additional modifiers specific to the commercial sector may be added, such as thresholds for maximum annual gross receipts or ownership criteria.
3 https://oehha.ca.gov/calenviroscreen
5 California Energy Commission, SB 350 Low-Income Barriers Study, available at:

E Empowering
Our Clean
Energy Future

CONTRA COSTA I MARIN I NAPA I SOLANO
MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 2 estimated 2.7 million MWh of electricity annually, which represents roughly 68% of all MCE non-residential consumption, and 35% of MCE’s total electricity load.

MCE has performed a preliminary data analysis of possible Program-eligible customers and has determined there are approximately 11,000 service accounts that may qualify. The following table identifies the business types that may be eligible:

Business Type Number of Service Accounts
Agricultural 89
Automobile Sales 239
Automotive Repair 479
Banking and Financial Services 441
Commercial Office 1,416
Commercial Wholesale 296
Contracting and Construction 472
Education 248
Entertainment 202
Gas Stations 74
Grocery 293
Health Care 414
Home Improvement and Furnishing 234
Lodging 76
Manufacturing 608
Miscellaneous 2,153
Public Agencies 932
Restaurants and Bars 651
Retail 537
Salon and Personal Care 342
Social Services 170
Telecommunications 535
Transportation and Trucking 168
Utilities and Industrial 145
Warehousing and Storage 77
Total 11,291
III. PURPOSE
The purpose of this RFP is to find a program implementer (“PI”) that can provide innovative design, administration, and management of the Program. The PI will collaborate with MCE staff to develop an innovative Program that provides the greatest benefit to MCE’s Equity Commercial Customers. Some of the desired benefits that the Program will provide include, but are not limited to:
• Filling gaps in services that are not currently provided by other MCE programs; MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 3 • Providing solutions or services that compliment or leverage existing programs in MCE’s service area;
• Sustained energy efficiency benefits, as well as those focused during the summer peak period of 4-9pm June - September.
• Creating value through behavioral modification or non-capital measures • Providing on-going technical support, commissioning, and training; • Reduced or no copays.
• Providing targeted marketing and direct networking within communities to reach Equity Commercial Customers; and
• Focusing on Non-Energy Benefits (“NEBs”), including a methodology to quantify its value.

There are many challenges to reaching Equity Commercial Customers and MCE is looking for a PI that can overcome barriers and make the proposed Program impactful. Some of the specific challenges for reaching Equity Commercial Customers include:

• Small commercial customers sometimes lack the staff bandwidth, specific technical expertise, or capital to invest in EE improvements.
• Split incentives exist between tenants and building owners that prevent upgrades because: (1) the building owner has a limited incentive to reduce utility bill costs when the tenant pays the utility bill; and/or (2) the tenant has limited incentive to invest in EE equipment since the tenant cannot take the EE equipment with them when they move. • Commercial EE programs tend to focus on larger commercial customers that present larger savings opportunities.
• Literacy and language barriers prevent some commercial customers from being informed of EE opportunities.
• Other issues identified in the California Energy Commissions SB 350 Low-Income Barriers Study.
5 IV. PROPOSED SCOPE OF WORK
A contract awarded as a result of this RFP will include the following proposed scope of work:

A. The selected PI shall develop and manage an EE program that benefits Equity Commercial Customers in MCE’s service area.
6 The selected PI’s services shall
include, but not be limited to:
1) Program Development
a. Assess emerging technologies and EE services and customize the Program to effectively impact MCE Equity Commercial Customers. b. Consider and incorporate local needs through a planned stakeholder outreach campaign. This should include
communications with community-based organizations (CBOs) that serve MCE’s Equity Commercial Customers.
5 California Energy Commission, SB 350 Low-Income Barriers Study, available at:
https://efiling.energy.ca.gov/getdocument.aspx?tn=214830h, pp. 4; 9-10; 64; 69-70. 6 https://www.mcecleanenergy.org/service-area/ MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 4 c. Collaborate with MCE staff to create an executable Program framework.
d. Develop and execute a Program Implementation Plan (“PIP”) inclusive of, but not limited to:
i. Program plan narrative and description, detailing how the Program will be implemented and how customer incentives will be delivered.
ii. Details of how Program performance and metrics will be reported, including metrics related to energy and NEBs. iii. Marketing and communication outreach plan.
iv. Measurement and verification (“M&V”) plan.
e. Create a quality assurance plan detailing how the Program will provide on-going technical support as needed.
2) Program Management
a. Provide all Program management tasks, as defined in the PIP. b. Provide administrative support throughout the Program period.

This includes, but is not limited to:
i. Development and periodic update of MCE’s: PIP, Program M&V plans, and Annual Budget Advice Letter(s), each to be submitted to the CPUC.
ii. Periodic reporting of Program progress and forecasting of energy savings, cost effectiveness, etc.
iii. M&V reporting.
iv. Submission of MCE’s Savings Claims to CPUC.
v. Provide ongoing quality assurance by evaluating projects and soliciting customer feedback.

B. The selected PI shall develop and manage a Program with the following requirements:
1) Collaborative and effective community engagement strategies, such as:
a. Engaging with CBOs and customers to assist in the design and promotion of the Program;
b. Soliciting feedback and incorporating stakeholder input into the Program;
c. Participating in biannual meetings to receive feedback from stakeholders.
2) Inclusion of participants that satisfy the above Criteria.

V. PROGRAM TIMELINE
The preliminary timeline for Program implementation is as follows:

Milestone Date
RFP Release August 29
Questions Due September 12
MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 5 Answers to Questions Issued September 19
Proposals Due September 26
Interviews October 10
Vendor Selection and Contract Negotiations October 24
Program Development January 2023
Program Launch April 2023
VI. PROGRAM BUDGET
MCE has secured funding from the CPUC for program year 2023 and has applied for funding for program years 2024-2027. Each expected program budget is inclusive of all associated costs for administering the Program, including direct costs and incentives.

Program Year Expected Program Budget
2023 $600,000*
2024 $944,320
2025 $920,244
2026 $923,722
2027 $912,564
*Funding secured

VII. REQUIRED CONTENT OF PROPOSALS
Proposals must include the following components in sufficient detail (using the proposed scope of work in Section IV):
a. Introduction/Cover Sheet. Briefly introduce the respondent organization and summarize the respondent organization’s most relevant experience in [the field or skills needed] b. Program Implementation Background and Experience: Detail the respondent organization’s previous experience developing and managing EE programs. Please describe program processes that the respondent organization has used to ensure program success and excellence. Provide an organizational chart, listing the key team members, including the program manager. Please include a description of roles and responsibilities and associated resumes.
c. Proposed Program Outline: Outline the key elements of the proposed program. Include planning steps, strategies and goals. Include details on the communication and marketing strategies that will be used to reach customers. Provide a methodology on how NEBs will be measured during the program. Provide detail on any innovative approaches and strategies to maximize value to MCE customers.

MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 6 d. Proposed Work Plan and Timeline: Describe the major tasks and estimated timeline required in order to complete the above proposed scope of work. e. Price: Proposals should include pricing for all services provided in or related to the proposed scope of work for which MCE would be billed. The program budget detailed above is inclusive of the customer incentive and the PI’s implementation fees for administering the Program. The following price table shall be used:

Program Year 2023 2024
Customer
Incentive/Rebate/Measure Budget
Direct Implementation Budget
Total $600,000 $944,320
f. Information and Resources Required from MCE: Please indicate what, if any, additional resources or information would be required from MCE in order to complete the proposed scope of work.
g. Statement of Qualifications: Describe the respondent organization’s specific qualifications which will enable it to develop workable solution(s) to address each point on the proposed scope of work. Attach copies of any relevant licenses and certifications. h. References: Provide three business references that can attest to the respondent organization’s work history and the general quality of work performed. i. Contract Terms: Review MCE’s Standard Form Agreement/Master Services Agreement (Attachment A) with the respondent organization’s legal department. If the respondent organization requires any deviations from MCE’s standard contract terms listed in Attachment A, the respondent organization must provide a redline with requested edits, or list the terms where the respondent organization will require an edit with sufficient detail explaining the need for such an edit.

VIII. EVALUATION CRITERIA

MCE will evaluate proposals using the following criteria:

Criteria Percent Weight
Program Implementation Experience 30%
Proposed Program Outline 30%
Proposed Work Plan and Timeline 20%
Program/Incentive Ratio 20%
MCE will utilize the criteria above to rank RFP responses. MCE may elect to invite top respondent organizations for an interview. Details of the interview will be shared with the respondent organization as appropriate.

MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 7 IX. KEY DEADLINES AND SUBMISSION REQUIREMENTS

a. Notice of Interest: A notice of interest in submitting an offer is not required, however, it is useful for the evaluation process. No later than the deadline for submitting questions, all parties interested in responding to this RFP are encouraged, but not required, to notify MCE via email of the intent to submit a proposal. This notice creates no obligation to submit a proposal but will ensure that interested parties are copied on MCE’s responses to questions submitted by potential respondents. Notices must be sent to [email protected] and should include the company’s name and email contact information, referencing “MCE Commercial Equity Energy Efficiency Program RFP – Notice of Interest” in the subject line.
b. Deadline for Questions. Any questions related to the content of this RFP must be submitted to the Contracts Manager no later than September 12. c. Deadline for Responses. MCE Responses to all questions received will be sent to all vendors on the distribution list via email by September 19 d. Submission Deadline. To be eligible for considerations, all responses must be submitted via the below Egnyte upload link, in either .pdf or .docx (Word) file format, no later than 4:00 p.m. PDT on September 26:
https://mea.egnyte.com/ul/IX27vJdozN
Respondents must fill in the two required fields as follows before uploading documents:

Name: Please list Company Name;
Email Address: List email address of the contact submitting the response.

Please leave the optional third field requesting company name blank; company name should be listed in the first required field titled “Name”.

Respondents may upload files until the deadline listed above. Any submissions received after the deadline will not be considered.
e. Selection of Contractor. Subject to the General Terms and Conditions below, MCE anticipates that the contractor selection process will be completed by October 24.

X. GENERAL TERMS AND CONDITIONS

A. MCE’s Reserved Rights. MCE may, at its sole discretion: withdraw this Request for Proposals at any time, and/or reject any or all offers or proposals submitted without awarding a contract. Respondents are solely responsible for any costs or expenses incurred in connection with the preparation and submittal of an offer or proposal.

B. Public Records. All documents submitted in response to this Request will become the property of MCE upon submittal, and will be subject to the provisions of the California Public Records Act and any other applicable disclosure laws. Upon submission, all proposals shall be treated as confidential until the selection process is completed. Once a contract is awarded, all proposals shall be deemed public record. MCE is required to comply with the California Public Records Act as it relates to the treatment of any information marked “confidential.” Respondents requesting that portions of its submittal MCE RFP 2022-05 for Commercial Equity Program – August 29, 2022 Page 8 should be exempt from disclosure must clearly identify those portions with the word “Confidential” printed on the lower right-hand corner of the page. Each page shall be clearly marked and separable from the proposal in order to facilitate public inspection of the non-confidential portion of the proposal. MCE will consider a respondent's request for an exemption from disclosure; however, if MCE receives a request for documents under the California Public Records Act, MCE will make a decision based upon applicable laws. Respondents should not over-designate material as confidential, and any requests or assertions by a respondent that the entire submittal, or significant portions thereof, are exempt from disclosure will not be honored.

C. No Guarantee of Contract. MCE makes no guarantee that a contractor and/or firm submitting documents under this solicitation will result in a contract. The successful vendor, if any, will enter into an agreement for services based on MCE’s Standard Form Agreement/Master Services Agreement, attached hereto as Attachment A. By submitting a response, you agree to abide by the terms included in the attached Agreement; however, MCE reserves the right to modify the terms based on the scope of work agreed to by MCE and the selected vendor.

D. Insurance. Selected vendors shall provide proof of insurance coverage meeting or exceeding the following minimum requirements prior to contracting with MCE:

Commercial General Liability ($2,000,000 per occurrence, $4,000,000 aggregate for bodily injury and property damage), Motor Vehicle Liability Insurance ($1,000,000), Workers’ Compensation and Employer’s Liability Insurance (per statute), and Professional Liability Insurance ($1,000,000), as applicable.

XI. QUESTIONS

To promote accuracy and consistency of information provided to all respondent organizations, questions will only be accepted via email submitted to MCE Contracts Manager at [email protected] and the subject line of the email must read “MCE Commercial Equity Program RFP Question.” The deadline for submitting questions is September 12, 2022 by 5:00 p.m.

MCE will provide a written response to the questions submitted via email by September 19, 2022 to all respondent organizations that submitted questions and/or provided a complete Notice of Interest. MCE reserves the right to combine similar questions, rephrase questions, or decline to answer questions, at its sole discretion.

All questions must be submitted through the above process. No questions will be answered over the telephone or in person. Respondent organizations may not have any contact regarding this procurement with any MCE official or staff from the time of issuance of this solicitation until the award of contract, other than through the process for submitting questions. Any contact in violation of these provisions will be grounds for disqualification.

Thank you in advance for your interest!
MCE Standard Form 001 (Updated 2/3/2021) (First) Agreement – MCE & CONTRACTOR NAME Page 1 of 13

ATTACHMENT A

MARIN CLEAN ENERGY

STANDARD SHORT FORM CONTRACT FOR VENDORS RECEIVING MCE DATA (FIRST) AGREEMENT

BY AND BETWEEN

MARIN CLEAN ENERGY AND (CONTRACTOR)
THIS (FIRST) AGREEMENT (“Agreement”) is made and entered into on [Date] by and between MARIN CLEAN ENERGY (hereinafter referred to as “MCE”) and [CONTRACTOR name], [a [state] [corporate form]] with principal address at: [address] (hereinafter referred to as “Contractor”) (each, a “Party,” and, together, the “Parties”).

RECITALS:

WHEREAS, MCE desires to retain Contractor to provide the services described in Exhibit A attached hereto and by this reference made a part hereof (“Services”);
WHEREAS, Contractor desires to provide the Services to MCE; NOW, THEREFORE, in consideration of the mutual covenants herein contained, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

1. SCOPE OF SERVICES:

Contractor agrees to provide all of the Services in accordance with the terms and conditions of this Agreement. “Services” shall also include any other work performed by Contractor pursuant to this Agreement.

2. FEES AND PAYMENT SCHEDULE; INVOICING:

The fees and payment schedule for furnishing Services under this Agreement shall be based on the rate schedule which is attached hereto as Exhibit B and by this reference incorporated herein. Said fees shall remain in effect for the entire term of the Agreement (“Term”). Contractor shall provide MCE with Contractor’s Federal Tax I.D. number prior to submitting the first invoice. Contractor is responsible for billing MCE in a timely and accurate manner. Contractor shall email invoices to MCE on a monthly basis for any Services rendered or expenses incurred hereunder. Fees and expenses invoiced beyond ninety (90) days will not be reimbursable. The final invoice must be submitted within thirty (30) days of completion of the stated scope of services or termination of this Agreement. MCE will process payment for undisputed invoiced amounts within thirty (30) days.

3. MAXIMUM COST TO MCE:

In no event will the cost to MCE for the Services to be provided herein exceed the maximum sum of $[___],000.

4. TERM OF AGREEMENT:

This Agreement shall commence on [Date] (“Effective Date”) and shall terminate on [Date], unless earlier terminated pursuant to the terms and conditions set forth in Section 12.

5. REPRESENTATIONS; WARRANTIES; COVENANTS:

5.1. CONTRACTOR REPRESENTATIONS AND WARRANTIES. Contractor represents, warrants and covenants that (a) [it is a [corporation/limited liability company] duly organized, validly existing and in good standing under the laws of the State of [insert state of organization]], (b) it has full power and authority and all regulatory authorizations required to execute, deliver and perform its obligations under this Agreement and all exhibits and addenda and to engage in the business it presently conducts and contemplates conducting, (c) it is and will be duly licensed or qualified to do business and in good standing under the laws of the State of California and each other jurisdiction wherein the nature of its business transacted by it makes such licensing or qualification necessary and where the failure to be licensed or qualified would have a material adverse effect on its ability to perform its obligations hereunder, (d) it is qualified and competent to render the Services and possesses the requisite expertise to perform its obligations hereunder, (e) the execution, delivery and performance of this Agreement and all exhibits and addenda hereto are within its powers and do not violate the terms and conditions in its governing documents, any contracts to which it is a party or any law, rule, regulation, order or the like applicable to it, (f) this Agreement and each exhibit and addendum constitutes its legally valid and binding obligation enforceable against it in accordance with its terms, and (g) it is not bankrupt and there are no proceedings pending or being contemplated by it or, to its knowledge, threatened against it which would result in it being or becoming bankrupt.

5.2. COMPLIANCE WITH APPLICABLE LAW: At all times during the Term and the performance of the Services, Contractor shall comply with all
SAMPLE
applicable federal, state and local laws, regulations, ordinances and resolutions (“Applicable Law”) MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 2 of 13

5.3. LICENSING. At all times during the performance of the Services, Contractor represents, warrants and covenants that it has and shall obtain and maintain, at its sole cost and expense, all required permits, licenses, certificates and registrations required for the operation of its business and the performance of the Services. Contractor shall promptly provide copies of such licenses and registrations to MCE at the request of MCE.

5.4. NONDISCRIMINATORY EMPLOYMENT: Contractor shall not unlawfully discriminate against any individual based on race, color, religion, nationality, sex, sexual orientation, gender identity, age or condition of disability. Contractor understands and agrees that Contractor is bound by and shall comply with the nondiscrimination mandates of all federal, state, and local statutes, regulations, and ordinances.

5.5. PERFORMANCE ASSURANCE; BONDING. At all times during the performance of the Services, Contractor represents, warrants and covenants that it has and shall obtain and maintain, at its sole cost and expense, all bonding requirements of the California Contractors State License Board (“CSLB”), as may be applicable. Regardless of the specific Services provided, Contractor shall also maintain any payment and/or performance assurances as may be requested by MCE during the performance of the Services.

5.6. SAFETY. At all times during the performance of the Services, Contractor represents, warrants and covenants that it shall:
(a) abide by all applicable federal and state Occupational Safety and Health Administration requirements and other applicable federal, state, and local rules, regulations, codes and ordinances to safeguard persons and property from injury or damage;
(b) abide by all applicable MCE security procedures, rules and regulations and cooperate with MCE security personnel whenever on MCE’s property;
(c) abide by MCE’s standard safety program contract requirements as may be provided by MCE to Contractor from time to time;
(d) provide all necessary training to its employees, and require Subcontractors to provide training to their employees, about the safety and health rules and standards required under this Agreement; (e) have in place an effective Injury and Illness Prevention Program that meets the requirements all applicable laws and regulations, including but not limited to Section 6401.7 of the California Labor Code. Additional safety requirements (including MCE’s standard safety program contract requirements) are set forth elsewhere in the Agreement, as applicable, and in MCE’s safety handbooks as may be provided by MCE to Contractor from time to time;
(f) be responsible for initiating, maintaining, monitoring and supervising all safety precautions and programs in connection with the performance of the Agreement; and
(g) monitor the safety of the job site(s), if applicable, during the performance of all Services to comply with all applicable federal, state, and local laws and to follow safe work practices.

5.7. BACKGROUND CHECKS.
(a) Contractor hereby represents, warrants and covenants that any employees, members, officers, contractors, Subcontractors and agents of Contractor (each, a “Contractor Party,” and, collectively, the “Contractor Parties”) having or requiring access to MCE’s assets, premises, customer property (“Covered Personnel”) shall have successfully passed background screening on each such individual, prior to receiving access, which screening may include, among other things to the extent applicable to the Services, a screening of the individual’s educational background, employment history, valid driver’s license, and court record for the seven (7) year period immediately preceding the individual’s date of assignment to perform the Services. (b) Notwithstanding the foregoing and to the extent permitted by applicable law, in no event shall Contractor permit any Covered Personnel to have one or more convictions during the seven (7) year period immediately preceding the individual’s date of assignment to perform the Services, or at any time after the individual’s date of, assignment to perform the Services, for any of the following (“Serious Offense”): (i) a “serious felony,” similar to those defined in California Penal Code Sections 1192.7(c) and 1192.8(a), or a successor statute, or (ii) any crime involving fraud (such as, but not limited to, crimes covered by California Penal Code Sections 476, 530.5, 550, and 2945, California Corporations Code 25540), embezzlement (such as, but not limited to, crimes covered by California Penal Code Sections 484 and 503 et seq.), or racketeering (such as, but not limited to, crimes covered by California Penal Code Section 186 or the Racketeer Influenced and Corrupt Organizations(“RICO”) Statute (18 U.S.C. Sections 1961‐ 1968)).
(c) To the maximum extent permitted by applicable law, Contractor shall maintain documentation related to such background and drug screening for all Covered Personnel and make it available to MCE for audit if required pursuant SAMPLE
to the audit provisions of this Agreement.

MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 3 of 13 (d) To the extent permitted by applicable law, Contractor shall notify MCE if any of its Covered Personnel is charged with or convicted of a Serious Offense during the term of this Agreement. Contractor shall also immediately prevent that employee, representative, or agent from performing any Services.

5.8. FITNESS FOR DUTY. Contractor shall ensure that all Covered Personnel report to work fit for their job. Covered Personnel may not consume alcohol while on duty and/or be under the influence of drugs or controlled substances that impair their ability to perform the Services properly and safely. Contractor shall, and shall cause its Subcontractors to, have policies in place that require their employees, contractors, subcontractors and agents to report to work in a condition that allows them to perform the work safely. For example, employees should not be operating equipment under medication that creates drowsiness.

5.9. QUALITY ASSURANCE PROCEDURES. Contractor shall comply with the following requirements (the “Quality Assurance Procedures”): [_______]. Additionally, Quality Assurance Procedures must include, but are not limited to: (i) industry standard best practices; (ii) procedures that ensure customer satisfaction; and (iii) any additional written direction from MCE.

5.10. ASSIGNMENT OF PERSONNEL. The Contractor shall not substitute any personnel for those specifically named in its proposal, if applicable, unless personnel with substantially equal or better qualifications and experience are provided, acceptable to MCE, as is evidenced in writing.

5.11. ACCESS TO CUSTOMER SITES: Contractor shall be responsible for obtaining any and all access rights for Contractor Parties, from customers and other third parties to the extent necessary to perform the Services. Contractor shall also procure any and all access rights from Contractor Parties, customers and other third parties in order for MCE and CPUC employees, representatives, agents, designees and contractors to inspect the Services.

6. INSURANCE:

At all times during the Term and the performance of the Services, Contractor shall maintain the insurance coverages set forth below. All such insurance coverage shall be substantiated with a certificate of insurance and must be signed by the insurer or its representative evidencing such insurance to MCE. The general liability policy shall be endorsed naming Marin Clean Energy and its employees, directors, officers, and agents as additional insureds. The certificate(s) of insurance and required endorsement shall be furnished to MCE prior to commencement of Services. Certificate(s) of insurance must be current as of the Effective Date, and shall remain in full force and effect through the Term. If scheduled to lapse prior to termination date, certificate(s) of insurance must be automatically updated before final payment may be made to Contractor. Each certificate of insurance shall provide for thirty (30) days’ advance written notice to MCE of any cancellation or reduction in coverage. Insurance coverages shall be payable on a per occurrence basis only, except those required by Section 6.4 which may be provided on a claims-made basis consistent with the criteria noted therein.

Nothing in this Section 6 shall be construed as a limitation on Contractor's indemnification obligations in Section 17 of this Agreement.

Should Contractor fail to provide and maintain the insurance required by this Agreement, in addition to any other available remedies at law or in equity, MCE may suspend payment to the Contractor for any Services provided during any period of time that insurance was not in effect and until such time as the Contractor provides adequate evidence that Contractor has obtained the required insurance coverage.

6.1. GENERAL LIABILITY. The Contractor shall maintain a commercial general liability insurance policy in an amount of no less than million dollars ($2,000,000) with a four million dollar ($4,000,000) aggregate limit. “Marin Clean Energy” shall be named as an additional insured on the commercial general liability policy and the certificate of insurance shall include an additional endorsement page (see sample form: ISO - CG 20 10 11 85).

6.2. AUTO LIABILITY (REQUIRED IF CHECKED ☐). Where the Services to be provided under this Agreement involve or require the use of any type of vehicle by Contractor in order to perform said Services, Contractor shall also provide comprehensive business or commercial automobile liability coverage including non-owned and hired automobile liability in the amount of one million dollars combined single limit ($1,000,000).

6.3. WORKERS’ COMPENSATION. The Contractor acknowledges that the State of California requires every employer to be insured against liability for workers’ compensation or to undertake self-insurance in accordance with the provisions of the Labor Code. If Contractor has employees, it shall comply with this requirement and a copy of the certificate evidencing such insurance or a copy of the Certificate of Consent to Self-Insure shall be provided to MCE prior to commencement of Services.

6.4. PROFESSIONAL LIABILITY INSURANCE (REQUIRED IF CHECKED ☐). Contractor shall maintain professional liability insurance with a policy limit of not less than $1,000,000 per incident. If the deductible or self-insured retention amount exceeds $100,000,
SAMPLE
MCE may ask for evidence that Contractor has segregated amounts in a special insurance reserve fund, or that MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 4 of 13 Contractor’s general insurance reserves are adequate to provide the necessary coverage and MCE may conclusively rely thereon. Coverages required by this subsection may be provided on a claims-made basis with a “Retroactive Date” prior to the Effective Date. If the policy is on a claims-made basis, coverage must extend to a minimum of twelve (12) months beyond termination of this Agreement. If coverage is cancelled or non-renewed, and not replaced with another claims made policy form with a “retroactive date” prior to the Effective Date, Contractor must purchase “extended reporting” coverage for a minimum of twelve (12) months after termination of this Agreement.

6.5. PRIVACY AND CYBERSECURITY LIABILITY (REQUIRED IF CHECKED ☐). Contractor shall maintain privacy and cybersecurity liability (including costs arising from data destruction, hacking or intentional breaches, crisis management activity related to data breaches, and legal claims for security breach, privacy violations, and notification costs) of at least $1,000,000 US per occurrence.

7. FINANCIAL STATEMENTS:

Contractor shall deliver financial statements on an annual basis or as may be reasonably requested by MCE from time to time. Such financial statements or documents shall be for the most recently available audited or reviewed period and prepared in accordance with generally-accepted accounting principles.

8. SUBCONTRACTING:

The Contractor shall not subcontract nor assign any portion of the work required by this Agreement without prior, written approval of MCE, except for any subcontract work expressly identified herein in Exhibit A. If Contractor hires a subcontractor under this Agreement (a “Subcontractor”), Subcontractor shall be bound by all applicable terms and conditions of this Agreement, and Contractor shall ensure the following:

8.1. Subcontractor shall comply with the following terms of this Agreement: Sections 9, 10, Exhibit A.

8.2. Subcontractor shall provide, maintain and be bound by the representations, warranties and covenants of Contractor contained in Section 5 hereof (as may be modified to be applicable to Subcontractor with respect to Section 5.1(a) hereof) at all times during the Term of such subcontract and its provision of Services.

8.3. Subcontractor shall comply with the terms of Section 6 above, including, but not limited to providing and maintaining insurance coverage(s) identical to what is required of Contractor under this Agreement, and shall name MCE as an additional insured under such policies. Contractor shall collect, maintain, and promptly forward to MCE current evidence of such insurance provided by its Subcontractor. Such evidence of insurance shall be included in the records and is therefore subject to audit as described in Section 9 hereof.

8.4. Subcontractor shall be contractually obligated to indemnify the MCE Parties (as defined in Section 17 hereof) pursuant to the terms and conditions of Section 17 hereof.

8.5. Subcontractors shall not be permitted to further subcontract any obligations under this Agreement.

Contractor shall be solely responsible for ensuring its Subcontractors’ compliance with the terms and conditions of this Agreement made applicable above and to collect and maintain all documentation and current evidence of such compliance. Upon request by MCE, Contractor shall promptly forward to MCE evidence of same. Nothing contained in this Agreement or otherwise stated between the Parties shall create any legal or contractual relationship between MCE and any Subcontractor, and no subcontract shall relieve Contractor of any of its duties or obligations under this Agreement. Contractor's obligation to pay its Subcontractors is an independent obligation from MCE’s obligation to make payments to Contractor. As a result, MCE shall have no obligation to pay or to enforce the payment of any monies to any Subcontractor.

9. RETENTION OF RECORDS AND AUDIT PROVISION:

Contractor shall keep and maintain on a current basis full and complete records and documentation pertaining to this Agreement and the Services, whether stored electronically or otherwise, including, but not limited to, valuation records, accounting records, documents supporting all invoices, employees’ time sheets, receipts and expenses, and all customer documentation and correspondence (the “Records”). MCE shall have the right, during regular business hours, to review and audit all Records during the Term and for at least five (5) years from the date of the completion or termination of this Agreement. Any review or audit may be conducted on Contractor's premises or, at MCE's option, Contractor shall provide all records within a maximum of fifteen (15) days upon receipt of written request from MCE.

Contractor shall refund any monies erroneously charged. Contractor shall have an opportunity to review and respond to or refute any report or summary of audit findings, and shall promptly refund any overpayments made by MCE based on undisputed audit findings.

10. DATA, CONFIDENTIALITY AND INTELLECTUAL PROPERTY
SAMPLE
:

MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 5 of 13

10.1. DEFINITION OF “MCE DATA”. “MCE Data” shall mean all data or information provided by or on behalf of MCE, including but not limited to, customer Personal Information; energy usage data relating to, of, or concerning, provided by or on behalf of any customers; all data or information input, information systems and technology, software, methods, forms, manuals, and designs, transferred, uploaded, migrated, or otherwise sent by or on behalf of MCE to Contractor as MCE may approve of in advance and in writing (in each instance); account numbers, forecasts, and other similar information disclosed to or otherwise made available to Contractor. MCE Data shall also include all data and materials provided by or made available to Contractor by MCE’s licensors, including but not limited to, any and all survey responses, feedback, and reports subject to any limitations or restrictions set forth in the agreements between MCE and their licensors. “Confidential Information” under this Agreement shall have the same meaning as defined in the Marin Clean Energy Non-Disclosure Agreement between the Parties dated [MONTH, DAY, YEAR].

10.2. DEFINITION OF “PERSONAL INFORMATION”. “Personal Information” includes but is not limited to the following: personal and entity names, e-mail addresses, addresses, phone numbers, any other public or privately-issued identification numbers, IP addresses, MAC addresses, and any other digital identifiers associated with entities, geographic locations, users, persons, machines or networks. Contractor shall comply with all applicable federal, state and local laws, rules, and regulations related to the use, collection, storage, and transmission of Personal Information.

10.3. MCE DATA SECURITY MEASURES. Prior to Contractor receiving any MCE Data, Contractor shall comply, and at all times thereafter continue to comply, in compliance with MCE’s Data security policies set forth in MCE Policy 009 (available upon request) and MCE’s Advanced Metering Infrastructure (AMI) Data Security and Privacy Policy (“Security Measures”) and pursuant to MCE’s Confidentiality provisions in Section 5 of the Marin Clean Energy Non-Disclosure Agreement between the parties dated [DAY MONTH YEAR], and as set forth in MCE Policy 001 - Confidentiality. MCE’s Security Measures and Confidentiality provisions require Contractor to adhere to reasonable administrative, technical, and physical safeguard protocols to protect the MCE’s Data from unauthorized handling, access, destruction, use, modification or disclosure.

10.4. CONTRACTOR DATA SECURITY MEASURES. Additionally, Contractor shall, at its own expense, adopt and continuously implement, maintain and enforce reasonable technical and organizational measures consistent with the sensitivity of Personal Information and Confidential Information including, but not limited to, measures designed to (1) prevent unauthorized access to, and otherwise physically and electronically protect, the Personal Information and Confidential Information, and (2) protect MCE content and MCE Data against unauthorized or unlawful access, disclosure, alteration, loss, or destruction.

10.5. RETURN OF MCE DATA. Promptly after this Agreement terminates, (i) Contractor shall securely destroy all MCE Data in its possession and certify the secure destruction in writing to MCE, and (ii) each Party shall return (or if requested by the disclosing Party, destroy) all other Confidential Information and property of the other (if any), provided that Contractor’s attorney shall be permitted to retain a copy of such records or materials solely for legal purposes.

10.6. OWNERSHIP AND USE RIGHTS.
a) MCE Data. Unless otherwise expressly agreed to in writing by the Parties, MCE shall retain all of its rights, title and interest in MCE’s Data.
b) Intellectual Property. Unless otherwise expressly agreed to in writing by the Parties, any and all materials, information, or other intellectual property created, prepared, accumulated or developed by Contractor or any Contractor Party under this Agreement (“Intellectual Property”), including finished and unfinished inventions, processes, templates, documents, drawings, computer programs, designs, calculations, valuations, maps, plans, workplans, text, filings, estimates, manifests, certificates, books, specifications, sketches, notes, reports, summaries, analyses, manuals, visual materials, data models and samples, including summaries, extracts, analyses and preliminary or draft materials developed in connection therewith, shall be owned by MCE. MCE shall have the exclusive right to use Intellectual Property in its sole discretion and without further compensation to Contractor or to any other party. Contractor shall, at MCE’s expense, provide Intellectual Property to MCE or to any party MCE may designate upon written request. Contractor may keep one file reference copy of Intellectual Property prepared for MCE solely for legal purposes and if otherwise agreed to in writing by MCE. In addition, Contractor may keep one copy of Intellectual Property if otherwise agreed to in writing by MCE. c) Intellectual Property shall be owned by MCE upon its creation. Contractor agrees to execute any such other documents or take other actions as MCE may reasonably request to perfect MCE’s ownership in the Intellectual Property. d) Contractor’s Pre‐Existing Materials. If, and to the extent Contractor retains any preexisting ownership rights (“Contractor’s Pre‐Existing Materials”) in any of the materials furnished to be used to create, develop, and prepare the Intellectual Property, Contractor hereby grants MCE on behalf of its customers and the CPUC for governmental and regulatory purposes an irrevocable, assignable, non‐exclusive, perpetual, fully paid up, worldwide, royalty‐free, unrestricted license to use and sublicense others to use, reproduce, display, prepare and develop derivative works, SAMPLE
perform, distribute copies of any intellectual or proprietary property right of Contractor or any Contractor Party for the sole MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 6 of 13 purpose of using such Intellectual Property for the conduct of MCE’s business and for disclosure to the CPUC for governmental and regulatory purposes related thereto. Unless otherwise expressly agreed to by the Parties, Contractor shall retain all of its rights, title and interest in Contractor’s Pre‐Existing Materials. Any and all claims to Contractor’s Pre‐ Existing Materials to be furnished or used to prepare, create, develop or otherwise manifest the Intellectual Property must be expressly disclosed to MCE prior to performing any Services under this Agreement. Any such Pre-Existing Material that is modified by work under this Agreement is owned by MCE.

10.7.EQUITABLE RELIEF. Each Party acknowledges that a breach of this Section 10 would cause irreparable harm and significant damages to the other Party, the degree of which may be difficult to ascertain. Accordingly, each Party agrees that MCE shall have the right to obtain immediate equitable relief to enjoin any unauthorized use or disclosure of MCE Data or Personal Information, in addition to any other rights and remedies that it may have at law or otherwise; and Contractor shall have the right to obtain immediate equitable relief to enjoin any unauthorized use or disclosure of Contractor’s Pre-Existing Materials, in addition to any other rights and remedies that it may have at law or otherwise.

11. FORCE MAJEURE:

A Party shall be excused for failure to perform its obligations under this Agreement if such obligations are prevented by an event of Force Majeure (as defined below), but only for so long as and to the extent that the Party claiming Force Majeure (“Claiming Party”) is actually so prevented from performing and provided that (a) the Claiming Party gives written notice and full particulars of such Force Majeure to the other Party (the “Affected Party”) promptly after the occurrence of the event relied on, (b) such notice includes an estimate of the expected duration and probable impact on the performance of the Claiming Party’s obligations under this Agreement, (c) the Claiming Party furnishes timely regular reports regarding the status of the Force Majeure, including updates with respect to the data included in Section 10 above during the continuation of the delay in the Claiming Party’s performance, (d) the suspension of such obligations sought by Claiming Party is of no greater scope and of no longer duration than is required by the Force Majeure, (e) no obligation or liability of either Party which became due or arose before the occurrence of the event causing the suspension of performance shall be excused as a result of the Force Majeure; (f) the Claiming Party shall exercise commercially reasonable efforts to mitigate or limit the interference, impairment and losses to the Affected Party; (g) when the Claiming Party is able to resume performance of the affected obligations under this Agreement, the Claiming Party shall give the Affected Party written notice to that effect and promptly shall resume performance under this Agreement. “Force Majeure” shall mean acts of God such as floods, earthquakes, fires, orders or decrees by a governmental authority, civil or military disturbances, wars, riots, terrorism or threats of terrorism, utility power shutoffs, strikes, labor disputes, pandemic, or other forces over which the responsible Party has no control and which are not caused by an act or omission of such Party.

12. TERMINATION:

12.1. If the Contractor fails to provide in any manner the Services required under this Agreement, otherwise fails to comply with the terms of this Agreement, violates any Applicable Law, makes an assignment of any general arrangement for the benefit of creditors, files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause under any bankruptcy or similar law for the protection of creditors, or has such petition filed against it, otherwise becomes bankrupt or insolvent (however evidenced), or becomes unable to pay its debts as they fall due, then MCE may terminate this Agreement by giving five (5) business days’ written notice to Contractor.

12.2.Either Party hereto may terminate this Agreement for any reason by giving thirty (30) calendar days’ written notice to the other Party. Notice of termination shall be by written notice to the other Party and be sent by registered mail or by email to the email address listed in Section 19.

12.3. In the event of termination not the fault of the Contractor, the Contractor shall be paid for Services performed up to the date of termination in accordance with the terms of this Agreement so long as proof of required insurance is provided for the periods covered in the Agreement or Amendment(s). Notwithstanding anything contained in this Section 12, in no event shall MCE be liable for lost or anticipated profits or overhead on uncompleted portions of the Agreement. Contractor shall not enter into any agreement, commitments or subcontracts that would incur significant cancelation or termination costs without prior written approval of MCE, and such written approval shall be a condition precedent to the payment of any cancellation or termination charges by MCE under this Section 12. Also, as a condition precedent to the payment of any cancellation or termination charges by MCE under this Section 12, Contractor shall have delivered to MCE any and all Intellectual Property (as defined in Section

10.1(b)) prepared for MCE before the effective date of such termination.

12.4. MCE may terminate this Agreement if funding for this Agreement is reduced or eliminated by a third-party funding source.

12.5. Without limiting the foregoing, if either Party’s activities hereunder become subject to law or regulation of any kind, which renders the activity illegal, unenforceable, or which imposes additional costs on such Party for which the parties cannot mutually agree upon an acceptable price modification, then such Party shall at such time have the right to terminate this Agreement upon written notice to the other Party with respect to the illegal, unenforceable, or uneconomic provisions only, and the remaining provisions will remain in full force and effect.

12.6. Upon termination of this Agreement for any reason, Contractor shall and shall cause each Contractor Party to bring the Services to an orderly conclusion as directed by MCE and shall return all MCE Data (as defined in Section 10.1(a) above) and Intellectual Property to MCE.

SAMPLE
MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 7 of 13

12.7. Notwithstanding the foregoing, this Agreement shall be subject to changes, modifications, or termination by order or directive of the California Public Utilities Commission (“CPUC”). The CPUC may from time to time issue an order or directive relating to or affecting any aspect of this Agreement, in which case MCE shall have the right to change, modify or terminate this Agreement in any manner to be consistent with such order or directive.

12.8. Notwithstanding any provision herein to the contrary, Sections 2, 3, 8.4, 9, 10, 12, 15, 16, 17, 18, 19, 20, 21, 22, 24, Exhibit B of this Agreement shall survive the termination or expiration of this Agreement.

13. ASSIGNMENT:

The rights, responsibilities, and duties under this Agreement are personal to the Contractor and may not be transferred or assigned without the express prior written consent of MCE.

14. AMENDMENT; NO WAIVER:

This Agreement may be amended or modified only by written agreement of the Parties. Failure of either Party to enforce any provision or provisions of this Agreement will not waive any enforcement of any continuing breach of the same provision or provisions or any breach of any provision or provisions of this Agreement.

15. DISPUTES:

Either Party may give the other Party written notice of any dispute which has not been resolved at a working level. Any dispute that cannot be resolved between Contractor’s contract representative and MCE’s contract representative by good faith negotiation efforts shall be referred to Legal Counsel of MCE and an officer of Contractor for resolution. Within 20 calendar days after delivery of such notice, such persons shall meet at a mutually acceptable time and place, and thereafter as often as they reasonably deem necessary to exchange information and to attempt to resolve the dispute. If MCE and Contractor cannot reach an agreement within a reasonable period of time (but in no event more than 30 calendar days), MCE and Contractor shall have the right to pursue all rights and remedies that may be available at law or in equity. All negotiations and any mediation agreed to by the Parties are confidential and shall be treated as compromise and settlement negotiations, to which Section 1119 of the California Evidence Code shall apply, and Section 1119 is incorporated herein by reference.

16. JURISDICTION AND VENUE:

This Agreement shall be construed in accordance with the laws of the State of California and the Parties hereto agree that venue shall be in Marin County, California.

17. INDEMNIFICATION:

To the fullest extent permitted by Applicable Law, Contractor shall indemnify, defend, and hold MCE and its employees, officers, directors, representatives, and agents (“MCE Parties”), harmless from and against any and all actions, claims, liabilities, losses, costs, damages, and expenses (including, but not limited to, litigation costs, attorney's fees and costs, physical damage to or loss of tangible property, and injury or death of any person) arising out of, resulting from, or caused by: a) the negligence, recklessness, intentional misconduct, fraud of all Contractor Parties; b) the failure of a Contractor Party to comply with the provisions of this Agreement or Applicable Law; or c) any defect in design, workmanship, or materials carried out or employed by any Contractor Party.

18. NO RECOURSE AGAINST CONSTITUENT MEMBERS OF MCE:

MCE is organized as a Joint Powers Authority in accordance with the Joint Exercise of Powers Act of the State of California (Government Code Section 6500, et seq.). Pursuant to MCE’s Joint Powers Agreement, MCE is a public entity separate from its constituent members. MCE shall solely be responsible for all debts, obligations, and liabilities accruing and arising out of this Agreement. No Contractor Party shall have rights and nor shall any Contractor Party make any claims, take any actions, or assert any remedies against any of MCE’s constituent members in connection with this Agreement.

SAMPLE
MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 8 of 13

19. INVOICES; NOTICES:

This Agreement shall be managed and administered on MCE’s behalf by the Contract Manager named below. All invoices shall be submitted by email to:

Email Address: [email protected]
All other notices shall be given to MCE at the following location:

Contract Manager: Troy Nordquist
MCE Address: 1125 Tamalpais Avenue
San Rafael, CA 94901
Email Address: [email protected]
Telephone No.: (925) 378-6767
Notices shall be given to Contractor at the following address:

Contractor:

Address:

Email Address:

Telephone No.:

20. ENTIRE AGREEMENT; ACKNOWLEDGMENT OF EXHIBITS:

This Agreement along with the attached Exhibits marked below constitutes the entire Agreement between the Parties. In the event of a conflict between the terms of this Agreement and the terms in any of the following Exhibits, the terms in this Agreement shall govern. ☒ Check applicable Exhibits CONTRACTOR’S INITIALS MCE’S INITIALS EXHIBIT A. ☒ Scope of Services
EXHIBIT B. ☒ Fees and Payment
EXHIBIT C. ☒ Energy Efficiency Program Terms

21. SEVERABILITY:

Should any provision of this Agreement be held invalid or unenforceable by a court of competent jurisdiction, such invalidity will not invalidate the whole of this Agreement, but rather, the remainder of the Agreement which can be given effect without the invalid provision, will continue in full force and effect and will in no way be impaired or invalidated.

SAMPLE
-
MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 9 of 13

22. INDEPENDENT CONTRACTOR:

Contractor is an independent contractor to MCE hereunder. Nothing in this Agreement shall establish any relationship of partnership, joint venture, employment or franchise between MCE and any Contractor Party. Neither MCE nor any Contractor Party will have the power to bind the other or incur obligations on the other’s behalf without the other’s prior written consent, except as otherwise expressly provided for herein.

23. TIME:

Time is of the essence in this Agreement and each and all of its provisions.

24. THIRD PARTY BENEFICIARIES:

The Parties agree that there are no third-party beneficiaries to this Agreement either express or implied.

25. FURTHER ACTIONS:

The Parties agree to take all such further actions and to execute such additional documents as may be reasonably necessary to effectuate the purposes of this Agreement.

26. PREPARATION OF AGREEMENT:

This Agreement was prepared jointly by the Parties, each Party having had access to advice of its own counsel, and not by either Party to the exclusion of the other Party, and this Agreement shall not be construed against either Party as a result of the manner in which this Agreement was prepared, negotiated or executed.

27. DIVERSITY SURVEY:

Pursuant to Senate Bill 255 which amends Section 366.2 of the California Public Utilities Code, MCE is required to submit to the California Public Utilities Commission an annual report regarding its procurement from women-owned, minority-owned, disabled veteran-owned and LGBT-owned business enterprises (“WMDVLGBTBE”). Consistent with these requirements, Contractor agrees to provide information to MCE regarding Contractor’s status as a WMDVLGBTBE and any engagement of WMDVLGBTBEs in its provision of Services under this Agreement. Concurrently with the execution of this Agreement, Contractor agrees to complete and deliver MCE’s Supplier Diversity Survey, found at the following link: https://forms.gle/DUBkcdFCskb7NNcA8 (the “Diversity Survey”). Because MCE is required to submit annual reports and/or because the Diversity Survey may be updated or revised during the term of this Agreement, Contractor agrees to complete and deliver the Diversity Survey, an updated or revised version of the Diversity Survey or a similar survey at the reasonable request of MCE and to otherwise reasonably cooperate with MCE to provide the information described above. Contractor shall provide all such information in the timeframe reasonably requested by MCE.

28. COUNTERPARTS:

This Agreement may be executed in one or more counterparts, each of which shall be deemed an original and all of which shall be deemed one and the same Agreement.

IN WITNESS WHEREOF, the parties have executed this Agreement on the date first above written.

APPROVED BY
Marin Clean Energy:

By: __________________________________
Name: _______________________________
Title: _________________________________
Date: _________________________________
By: __________________________________
Chairperson
Date: ________________________________
CONTRACTOR:

By: __________________________________
Name: _______________________________
Title: _________________________________
Date: ________________________________ SAMPLE
MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 10 of 13

EXHIBIT A

SCOPE OF SERVICES
Contractor shall provide the following Services under the Agreement as requested and directed by MCE staff, up to the maximum time/fees allowed under this Agreement:

SAMPLE
MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 11 of 13

EXHIBIT B

FEES AND PAYMENT SCHEDULE
For Services provided under this Agreement, MCE shall pay Contractor in accordance with the amount(s) and the payment schedule as specified below:

In no event shall the total cost to MCE for the services provided herein exceed the maximum sum of $,000 for the term of the Agreement.

SAMPLE
MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 12 of 13

EXHIBIT C
Energy Efficiency Program Terms
The terms below shall apply to all Contractor Parties providing Services under the [Program Name] (“Program”).

1. BILLING, ENERGY USE, AND PROGRAM TRACKING DATA (REQUIRED IF CHECKED ☐). a) Contractor shall comply with and timely cooperate with all CPUC directives, activities, and requests regarding the Program and Project evaluation, measurement, and verification (“EM&V”). For the avoidance of doubt, it is the responsibility of Contractor to be aware of all CPUC requirements applicable to the Services of this Agreement. b) Contractor shall make available to MCE upon demand, detailed descriptions of the program, data tracking systems, baseline conditions, and participant data, including financial assistance amounts. c) Contractor shall make available to MCE any revisions to Contractor's program theory and logic model (“PTLM”) and results from its quality assurance procedures, and comply with all MCE EM&V requirements, including reporting of progress and evaluation metrics.

2. WORKFORCE STANDARDS (REQUIRED IF CHECKED ☐).

At all times during the Term of the Agreement, Contractor shall comply with, and shall cause all Contractor Parties to comply with, the workforce qualifications, certifications, standards and requirements set forth in this Exhibit D, Section 2 (“Workforce Standards”). The Workforce Standards shall be included in their entirety in MCE’s Final Implementation Plan. If applicable, “Final Implementation Plan” is defined in the deliverables for the Services listed in Exhibit A. Prior to commencement of any Services, once per calendar year, and at any other time as may be requested by MCE, Contractor shall provide all documentation necessary to demonstrate to MCE’s reasonable satisfaction that Contractor has complied with the Workforce Standards.

2.1. HVAC STANDARDS (REQUIRED IF CHECKED ☐). For any non-residential project pursuant to this Agreement installing, modifying or maintaining a Heating Ventilation and Air Conditioning (“HVAC”) system or component with incentives valued at $3,000 or more, Contractor shall ensure that each worker or technician involved in the project, including all employees and agents of its Subcontractors, meets at least one of the following workforce criteria:
a) Completed an accredited HVAC apprenticeship;
b) Is enrolled in an accredited HVAC apprenticeship;
c) Completed at least five years of work experience at the journey level as defined by the California Department of Industrial Relations, Title 8, Section 205, of the California Code of Regulations, passed a practical and written HVAC system installation competency test, and received credentialed training specific to the installation of the technology being installed; or
d) Has a C-20 HVAC contractor license issued by the California Contractor’s State Licensing Board.

This standard shall not apply where the incentive is paid to any manufacturer, distributor, or retailer of HVAC equipment, unless the manufacturer, distributor, or retailer installs or contracts for the installation of the equipment.

2.2. ADVANCED LIGHTING CONTROLS STANDARDS (REQUIRED IF CHECKED ☐). For any non-residential project pursuant to this Agreement involving installation, modification, or maintenance of lighting controls with incentives valued at $2,000 or more, Contractor shall ensure that all workers or technicians involved in the project, including those of its Subcontractors are certified by the California Advanced Lighting Controls Training Program (“CALTP”). This requirement shall not apply where the incentive is paid to a manufacturer, distributor, or retailer of lighting controls unless the manufacturer, distributor, or retailer installs or contracts for installation of the equipment.

3. COORDINATION WITH OTHER PROGRAM ADMINISTRATORS (REQUIRED IF CHECKED ☐).

Contractor shall coordinate with other Program Administrators, including investor-owned utilities and local government agencies authorized by the CPUC to implement CPUC-directed energy efficient programs, administering energy efficiency programs in the same geographic area as MCE. These other Program Administrators include: Pacific Gas and Electric Company and Bay Area Regional Energy Network. The CPUC may develop further rules related to coordination between Program Administrators in the same geographic area, and any Contractor is required to comply with such rules.

4. MEASUREMENT AND VERIFICATION REQUIREMENTS, INCLUDING GUIDELINES ABOUT NORMALIZED METERED ENERGY CONSUMPTION (“NMEC”) DESIGN REQUIREMENTS (REQUIRED IF CHECKED ☐).

Contractor shall:

1. Only enroll customers that qualify for Program services.

2. Comply with current policies, procedures, and other required documentation as required by MCE;

3. SAMPLE
Report Customer Participation Information to MCE.

MCE Standard Form 001 (Updated 2/22/2022) (First) Agreement – MCE & CONTRACTOR NAME Page 13 of 13

4. Work with MCE’s evaluation team to define Program‐specific data collection and evaluability requirements, and in the case of NMEC which independent variables shall be normalized.

Throughout the Term, MCE may identify new net lifecycle energy savings estimates, net‐to‐ gross ratios, effective useful lives, or other values that may alter Program Net Lifecycle Energy Savings, as defined in Exhibit A, if applicable. Contractor shall use modified values upon MCE’s request, provided MCE modifies Contractor’s Program budget and/or overall Program net lifecycle Energy Savings consistent with the requested change. MCE shall determine any budget increases or decreases in its sole discretion.

For Programs claiming to‐code savings: Contractor shall comply with Applicable Law and work with MCE to address elements in its Program designs and Implementation Plans, such as:

1. Identifying where to‐code savings potential resides;

2. Specifying which equipment types, building types, geographic allocations, and/or customer segments promise cost‐ effective to‐code savings;

3. Describing the barriers that prevent code‐compliant equipment replacements;

4. Explaining why natural turnover is not occurring within certain markets or for certain technologies; and

5. Detailing the program interventions that would effectively accelerate equipment turnover.

SAMPLE

DECEMBER FILINGS

BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking Regarding
Policies, Procedures and Rules for the Self-Generation Incentive Program and Related Issues.

Rulemaking 20-05-012

COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS ON
ASSIGNED COMMISSIONER’S RULING
Nikhil Vijaykar

KEYES & FOX LLP
580 California St., 12th Floor
San Francisco, CA 94104
Telephone: (408) 621-3256
E-mail: [email protected]
On behalf of Joint Community Choice
Aggregators
December 2, 2022
i

TABLE OF CONTENTS
I. INTRODUCTION..................................................................................................................1 II. RESPONSES TO QUESTIONS IN ACR..............................................................................2 III. CONCLUSION ....................................................................................................................18 1 BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking Regarding
Policies, Procedures and Rules for the Self-Generation Incentive Program and Related Issues.

Rulemaking 20-05-012

COMMENTS OF THE JOINT COMMUNITY CHOICE AGGREGATORS ON
ASSIGNED COMMISSIONER’S RULING
Pursuant to the procedural schedule established in the October 26, 2022 Assigned Commissioner’s Ruling Seeking Comments on Improving Self-Generation Incentive Program Equity Outcomes and Assembly Bill 209 Implementation (ACR), the Joint Community Choice Aggregators1 (Joint CCAs) hereby submit these Opening Comments on the ACR.

I. INTRODUCTION
The Joint CCAs are encouraged by the substantial funding that Assembly Bill (AB) 209 directs to the Self-Generation Incentive Program (SGIP). SGIP is a foundational, imperative program that supports both bundled and unbundled customers. The Joint CCAs are eager to see the program grow and better achieve equity outcomes.

SGIP has been a key catalyst to the deployment of energy storage systems across California. The Joint CCAs support a transition to a more decentralized grid built on distributed energy storage and other distributed energy resources (DERs)—a trend the state has recognized and facilitated through proceedings at this California Public Utilities Commission (CPUC or 1 The Joint CCAs consist of East Bay Community Energy (EBCE), Marin Clean Energy (MCE), Peninsula Clean Energy Authority (PCE), San José Clean Energy (SJCE), and Sonoma Clean Power Authority (SCP). SJCE is the City of San José’s CCA program, which the San José Community Energy Department administers.
2 Commission)2 and the California Energy Commission (CEC).3 Distributed energy storage can complement distributed generation and reduce infrastructure needs (and associated costs) related to building and transit electrification over the coming decades. A decentralized grid can also help enhance customer resiliency, which has become an urgent imperative in light of Public Safety Power Shutoff (PSPS) events, growing wildfire threats, reliability challenges and the increasing frequency of “fast-trip” outages as a result of Pacific Gas and Electric Company’s (PG&E) Enhanced Powerline Safety Settings (EPSS) program.

AB 209 appropriately focuses SGIP on low-income customers4 going forward. The Joint CCAs are strongly supportive of that emphasis and submit these comments to recommend modifications to SGIP’s structure and design that will help improve the program’s equity outcomes. These comments are based on the Joint CCAs’ several years of experience offering a diverse set of energy storage programs to their customers—including low-income customers—in coordination with SGIP incentives. Appendix A to these comments describes the Joint CCAs’ depth of experience in this area.

II. RESPONSES TO QUESTIONS IN ACR
Below, the Joint CCAs provide feedback in response to both the ACR’s overarching question on AB 209 funding allocation as well as several of the ACR’s questions across nine topic areas. The Joint CCAs focus their feedback, however, on three priority issue areas that will drive 2 See, e.g., Order Instituting Rulemaking to Modernize the Electric Grid for a High Distributed Energy Resources Future, Rulemaking (R.) 21-06-017 (Jul. 2, 2021); Order Instituting Rulemaking to Consider Distributed Energy Resource Program Cost-Effectiveness Issues, Data Use and Access, and Equipment Performance Standards, R.22-11-013 (Nov. 17, 2022).
3 See, e.g., Cal. Energy Comm’n, Order Instituting Informational Proceeding on Distributed Energy Resources in California’s Energy Future, 22-OII-01 (Mar. 11, 2022). 4 AB 209 emphasizes low-income residential customer. The Joint CCAs use the term “low-income customers” in these comments synonymously with “low-income residential customers.” 3 SGIP’s success in delivering equity outcomes: 1) funding allocation; 2) eligibility criteria; and 3) incentive levels.

Overarching Question: Funding Allocation
Question 1: How should the AB 209 funding be allocated across SGIP residential budget categories? In your answer be specific for each category of AB 209 funding:
a) $630 million for incentives for low-income residential customers installing new BTM solar photovoltaic systems paired with energy storage systems or new energy storage systems;
b) $270 million for incentives for residential customers who install new behind-the-meter energy storage systems (not income restricted) Joint CCA Answer to Question 1: The Commission should simplify SGIP residential budget categories to create only two tracks – the Residential General Market Budget ($270 million) and the Residential Equity Budget ($630 million).

The ACR concisely illustrates the gap between low-income customers (who have largely not benefited from SGIP) and non-low-income customers (who have greatly benefited from SGIP).

As the ACR observes, there is a “sizable disparit[y]” between the participation of low-income and non-low-income households in SGIP.5 Although the “Equity Resiliency” budget category—which offers attractive incentives at $1/Wh—has driven the completion of over 6,100 projects and is fully exhausted,6 low-income households account for only 1% of those completed projects.7 The vast majority of customers receiving SGIP incentives through the “Equity Resiliency” budget category are Medical Baseline customers who are not low-income.8 Meanwhile, nearly 50% of the funds in the “Equity” budget category remain unused.

Simply put, the “Equity Resiliency” and “Equity” budget categories have not driven low-income customer participation in SGIP. While the low levels of low-income customer participation in SGIP can be attributed in part to the program’s eligibility requirements and incentive levels (the 5 ACR at 6-7.
6 Id. at 6.
7 Id. at 8.
8 Id.
4 Joint CCAs recommend modifications to each of these components of SGIP, below), the Joint CCAs recommend that the Commission fundamentally restructure, consolidate and simplify SGIP budget categories in order to better ensure that low-income customers benefit from AB 209 funding.

Specifically, The Joint CCAs recommend that the Commission create two residential budget categories:
● The first, a “Residential General Market Budget,” should be dedicated to general market customers (i.e., all non-low-income customers). That budget category would subsume the existing “Small Residential Storage” and “Large Scale Storage” budget categories. It would also include non-low-income customers who meet the “resiliency” requirements for the existing “Equity Resiliency” budget category (e.g., non-low-income medical baseline customers located in High Fire-Threat Districts (HFTD)). The Commission should allocate $270 million of AB 209 funding to the Residential General Market Budget. ● The second, a “Residential Equity Budget,” should be dedicated to low-income customers only (the Joint CCAs outline proposed eligibility requirements for this budget category in response to Question 4, below). That budget category would subsume all low-income customers no matter their “resiliency” designation; i.e., it would cover the existing “Residential Storage Equity” budget category, and low-income customers under the existing “Equity Resiliency” budget category. It would also include low-income customers installing solar PV systems coupled with energy storage systems. The Commission should allocate $630 million of AB 209 funding to the Residential Equity Budget.

The Commission should adopt the Joint CCAs’ simplified budget proposal for three reasons. First, by allocating $630 million of AB 209 funding entirely to a single budget category dedicated to low-income customers, the Commission can help ensure that low-income customers actually receive that funding consistent with the legislature’s objectives and are not sidelined by non-low-income customers (in other words, the Commission can avoid the skewed distribution of incentives that currently characterizes the Equity Resiliency budget category). Second, by streamlining budget categories, the Commission can help correct the disruptive “stop-and-go” pattern that has historically characterized SGIP funding availability. Streamlined budget categories would minimize the risk of funding stalling in a narrow budget sub-category and help ensure that 5 AB 209 funding is efficiently deployed to all low-income customers that need SGIP incentives in order to move forward with projects. Third, simplified budget categories would not foreclose differentiated incentive levels within each budget category (in essence, the Commission has an opportunity to “decouple” incentive levels from budget categories). For instance, the Joint CCAs are supportive of higher incentives for resiliency customers within the Residential General Market Budget (e.g., non-low-income Medical Baseline customers). Differentiated incentive levels within single budget categories can help the Commission prioritize certain market segments without imposing inefficiencies on the overall SGIP budget structure.

Topic Area 4.1: Residential Low-Income Eligibility Criteria Across SGIP Budget Categories Question 2: What financial or non-financial barriers, if any, exist for low-income residential customers wishing to participate in SGIP’s Equity or Equity Resiliency Budgets? Joint CCA Answer to Question 2: Low-income customers face myriad barriers to participating in SGIP, but their inability to cover any out-of-pocket expenses is the most significant hurdle.

In the Joint CCAs’ experience, the large majority of low-income customers view energy storage systems as a luxury, not as a necessity. A significant proportion of low-income customers struggle to pay for basic household expenses such as housing, food and utilities, and therefore typically lack the resources to pay for an energy storage system (despite any financial net benefits it might deliver the customer over the system’s lifetime).

As such, out-of-pocket costs are the primary barrier to a low-income customer considering an investment in an energy storage system. The Joint CCAs note that low-income customers also face many of the same barriers that non-low-income customers face with respect to participation in SGIP, including challenges in finding reliable installers; limited program marketing by SGIP Program Administrators; burdensome program rules; and unpredictable final incentive awards. 6 Due to the inability of low-income customers to cover any out-of-pocket expenses, the Joint CCAs recommend that the Commission modify SGIP and cover 100% of total project costs for low-income customers. The Joint CCAs discuss this recommendation further in response to Question 7, below.

Question 4a) Should the Commission consider modifications of the existing SGIP eligibility criteria for low-income residential customers? If so: What modifications to the definition of a “low-income residential customer” should be considered and why? Please state whether the modification would likely increase or decrease low-income enrollment and provide any estimates available of the number of households that would qualify under your proposed definition and show any sources and calculations used in your estimates.

Joint CCA Answer to Question 4a: The Commission should tie eligibility for the Residential Equity Budget primarily to eligibility for the California Alternate Rates for Energy Program (CARE) or the Family Electric Rate Assistance Program (FERA) programs.

Under the current SGIP rules, both single-family and multi-family residential customers must reside in a deed-restricted or resale-restricted residence to be eligible for the equity budget category.9 In the Joint CCAs’ experience, finding customers with resale restrictions or equity sharing agreements has been extremely difficult (the substantial unused funding in the equity budget category reflect this challenge). Indeed, a significant number of affordable residences are not subject to use-restrictions. For example, only approximately 11% of multifamily housing units in California are deed-restricted.10 Furthermore, portions of these housing units are at risk of losing their affordability restrictions and converting to market-rate over the coming decade. As such, many residential low-income customers are currently, or could eventually be, precluded from participation in the SGIP.

The Joint CCAs submit that a more effective way for SGIP to reach low-income customers is to establish eligibility criteria that not only capture a higher percentage of those customers, but 9 SGIP Handbook at 35-36 (Aug. 29, 2022).
10 Cal. Dep’t of Housing and Community Development. California’s Housing Future: Challenges and Opportunities, Final Statewide Housing Assessment 2025 at 31-32 (Feb. 2018). 7 also allow customers, developers and program administrators (PAs) to easily determine whether the customer is eligible for the Residential Equity budget. The Joint CCAs specifically recommend that SGIP follow the lead of a variety of other low-income energy programs and define eligibility for the Residential Equity Budget category primarily based on the host customer’s eligibility for (or enrollment in) CARE or FERA, among other pathways to eligibility.11 Specifically, the Joint CCAs propose the following eligibility criteria for the SGIP Residential Equity Budget:
● Single Family:
▪ Single family homeowners that are eligible for, and/or enrolled in, CARE or FERA, or;
▪ Single-family homeowners that have participated in, or are eligible for, the SASH and DAC-SASH programs.
● Multi-family:
▪ Multifamily residential building of at least five rental housing units in which at least 80% of residents are eligible for, and/or enrolled in, CARE or FERA, or;
▪ Multifamily residential buildings that have participated in, or are eligible for, the Multifamily Whole Building Track under the Energy Savings Assistance (ESA) program, or;
▪ Multifamily residential buildings that have participated in, or are eligible for, the MASH or SOMAH programs.
12 The Joint CCAs also suggest that the Commission further investigate “categorical eligibility” for SGIP incentives through participation/eligibility in other, non-energy, State-funded support programs in order to further simplify the SGIP eligibility requirements. The Joint CCAs support the notion that low-income customers should “categorically” or automatically be eligible for SGIP if they are eligible for other State-provided support programs with similar income eligibility guidelines, such as the federal Supplemental Nutrition Assistance Program (SNAP) 11 Households with income at or below 200% of the Federal Poverty Level are eligible for CARE, households with incomes at or below 200-250% of the Federal Poverty Level are eligible for FERA. 12 The Joint CCAs use the term “Energy Equity Programs” to describe the SASH, DAC-SASH, MASH, SOMAH or Multifamily Whole Building ESA program in these comments. 8 (known as ‘CalFresh” in California) or the federal Special Supplemental Nutrition Program for Women, Infants and Children (WIC). The Commission should investigate the lessons learned regarding categorical eligibility from the CARE and LifeLine programs and apply them to the SGIP Residential Equity budget category.13
Question 4b) Are there existing definitions of “low-income residential customer” that are used in other federal or state incentive programs that are appropriate for SGIP? Joint CCA Answer to Question 4b): Yes, see the Joint CCAs’ answer to Question 4a) above, which recommends that the Commission use CARE or FERA eligibility, among eligibility to other low-income support programs, to establish eligibility for the SGIP Residential Equity Budget.

Question 4c) What documentation requirements, if any, should be required to verify low-income eligibility? How might documentation and enrollment for external programs be leveraged to facilitate program access?
Joint CCA Answer to Question 4c): The CARE/FERA income verification requirements can be applied to verify eligibility for the SGIP Equity Budget. The utilities should be responsible for verifying the customer's enrollment in other energy equity Programs.

CARE/FERA enrollment is reflected on a customer's utility bill. Linking SGIP Equity Budget eligibility to CARE/FERA eligibility would therefore simplify the customer identification and recruitment process for developers (with respect to those customers that are enrolled in CARE/FERA). As described further in response to Question 4d), below, however, the Joint CCAs do not support self-attestation to verify eligibility. SGIP should follow the example of the ESA program and require verification of CARE/ FERA eligibility at the Rebate Reservation stage to ensure that customers are in fact eligible for CARE/ FERA and hence the SGIP Equity Budget. 13 Customers may be eligible for CARE, for example, if they are enrolled in public assistance programs such as Medicaid/Medi-Cal, Healthy Homes A&B, National School Lunch’s Free Lunch Program (NSL), Low-Income Home Energy Assistance Program (LIHEAP), Supplemental Security Income (SSI), Head Start Income (Tribal only), Bureau of Indian Affairs General Assistance, and Temporary Assistance for Needy Families (TANF) or Tribal TANF. See more at https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy. 9 The utilities should be responsible for verifying enrollment in other energy equity Programs. Utilities are better equipped to verify a customer’s previous participation in an energy equity program as those programs are funded through the utility. Whereas customers are in many cases not aware of their previous participation in an energy equity program, it is the Joint CCAs’ understanding that utilities have ready access to the same information and can leverage that information to streamline the SGIP application and enrollment process for customers and developers.

Question 4d) Should SGIP allow self-attestation to verify income requirements? If yes, what safeguards, if any, should be in place to verify eligibility? Joint CCA Answer to Question 4d): The Joint CCAs do not believe that self-attestation is an appropriate method to verify eligibility for the SGIP Equity Budget.

The Joint CCAs do not believe that self-attestation is an appropriate method to verify that a customer meets the eligibility requirements for the SGIP Residential Equity Budget. While self-attestation would significantly streamline and simplify the SGIP application process (which the Joint CCAs wholeheartedly support), it does not provide adequate protection of ratepayer funds, particularly considering the significant costs of energy storage (and solar coupled with storage) resources. Limited SGIP funds should only be allocated to those customers that can prove that they meet the eligibility requirements of the program. This follows the example of other Energy Equity Programs such as the ESA program.

Question 4e): Should the Commission eliminate the current SGIP eligibility requirement for low-income customer energy storage incentives that a single-family residential customer must reside in a deed restricted or resale restricted residence? Why or why not? Joint CCA Response to Question 4e): Yes. See the Joint CCAs’ response to Question 4a), above.

Topic Area 4.2: Paying for Upfront System Costs
Question 7: Should the Commission consider allowing entire or partial upfront payments on behalf of the customer prior to installation for energy storage systems, including solar where relevant, 10 for low-income households? If so, what mechanism should be used to provide these payments and to whom (e.g., the developer, the host customer, or some other party)? What learnings from the PG&E and SCE upfront payments pilots are relevant?
Joint CCA Answer to Question 7: Yes, SGIP should provide partial upfront payments to project developers/installers after the Reservation Request is approved.

Yes, the Commission should allow partial upfront payments prior to the installation of energy storage (or solar coupled with storage) systems. In the interest of efficiency, these incentives should be paid directly to the installer and/or developer (i.e., the entity responsible for the purchase and installation of the system) after the Reservation Request is approved. It is generally not tenable for a developer or installer to assume project development costs upfront and receive reimbursement from SGIP months after incurring that cost. To not discourage developers from recruiting low-income customers (who often cannot pay for project costs out-of-pocket like General Market customers), SGIP should provide partial upfront payments to developers and/or installers for low-income customers. The Joint CCAs recommend that the SGIP PAs host a roundtable with eligible SGIP developers and installers to further discuss the level of upfront payment required, the frequency of payments and the assignment of roles and responsibilities between all involved parties.

Topic Area 4.4: Incentive Levels for Low-Income Customers Question 16: Should there be separate budget amounts for storage plus solar projects versus stand-alone storage, or one combined budget? Why or why not? If yes, what percentage of funding in each category is recommended and why?
Joint CCA Answer to Question 16: The Commission should have one combined budget for storage plus solar versus stand-alone storage projects.

See the Joint CCAs’ Answer to Question 1, above. The Joint CCAs further note that a single budget promotes customer choice and flexibility. Customers should be able to choose the technology configuration that meets their needs and that decision should not be influenced by the budget remaining in any given SGIP category.
11 Question 17: What should the incentive level be for AB 209 Low-Income Incentive projects per unit of installed storage capacity? Please explain your recommendation.

Joint CCA Answer to Question 17: SGIP must cover 100% of low-income customers’ total system costs in order to drive low-income customer participation in the program.

As the Joint CCAs explained in response to Question 2 above, any amount of out-of-pocket-cost represents a significant (and often insurmountable) hurdle for low-income customers seeking to participate in SGIP. As such, it is imperative that SGIP provide upfront incentives that cover 100% of total system costs for customers participating in the Residential Equity Budget (including customers installing standalone storage and customers installing storage coupled with solar PV). While the Joint CCAs acknowledge that this would represent a significant departure from current SGIP incentive levels, covering 100% of project costs is not uncommon among similar energy programs available to low-income customers in California. For example, the ESA program covers 100% of weatherization upgrades for eligible customers. Similarly, the SOMAH program may also cover the full cost of the portion of the photovoltaic (PV) system that offsets tenant load.
14 Importantly, the Joint CCAs believe that covering 100% of total system costs upfront is the only practical way to achieve meaningful low-income customer participation in SGIP.

The Joint CCAs’ recommendation is grounded in their experience working with several hundred residential low-income customers to support the installation of energy storage systems.

Those experiences have proven the need for incentives that cover 100% of total system costs.

MCE, for example, provided “gap funding” for low-income customers through its Energy Storage Program for those expenses that were not covered by SGIP. MCE also increased its gap funding for low-income customers to cover unexpected costs such as moving conduit from existing solar installs to meet code requirements or upgrading main panels. Without MCE’s gap funding, most 14 See SOMAH Handbook at https://calsomah.org/resources/program-handbook#Group3. 12 of the low-income customers participating in MCE’s Energy Storage Program would have dropped out of the program. Similarly, SCP’s SGIP Assistance Program paid contractors the entire SGIP incentive up-front and assisted customers with the application process. These two program elements significantly increased SGIP uptake in SCP’s territory. Of the 326 completed SGIP projects since launch of SCP’s program, over 25% (90 projects) received SCP’s SGIP Assistance.

While the Joint CCAs maintain that incentives covering 100% of total system costs are critical, the Joint CCAs offer additional clarifying recommendations with respect to the implementation of incentive levels for low-income customers.15 First, the Joint CCAs note that where a project receives funding or incentives from other (non-SGIP) sources, that funding should be subtracted from total system costs in order to arrive at the SGIP incentives that the project is eligible to receive.

Second, to prevent gaming and requests for unreasonably high incentives, the Joint CCAs support the establishment of guardrails on the incentive payments made to low-income customers.

The Commission might establish guardrails based on average project costs submitted to SGIP to date, adjusted for inflation, with a reasonable 30% adder to address the potential for greater project-specific costs. Alternatively, any equity project that is beyond the 90 percentile of project costs submitted to the SGIP could undergo automatic detailed cost screening. The Joint CCAs recommend that the Commission and SGIP PAs host a roundtable with SGIP stakeholders to further define these guardrails for SGIP equity incentive levels.

Third, the Joint CCAs recommend that SGIP retain the flexibility to adjust incentive levels between the Reservation Request and Incentive Claim stages, based on updated project cost 15 The Joint CCAs recommend that the SGIP Program Administrators host a roundtable with eligible SGIP developers and installers to further discuss the level of upfront payment required, the frequency of payments and the assignment of roles and responsibilities between all involved parties. 13 information submitted by the applicant. The Joint CCAs have observed that project costs can rise dramatically from month-to-month (recently, fueled by supply chain issues and by the COVID-19 pandemic). Allowing SGIP the flexibility to adjust incentive levels (within the guardrails discussed above) can help ensure that low-income customers do not have to cancel projects due to a sharp increase in project costs between the Reservation Request and Incentive Claim stages.

Question 18: What should the incentive level(s) be for AB 209 Low-Income Incentive projects per unit of installed solar generation capacity? Please explain your recommendation Joint CCA Answer to Question 18: To facilitate low-income customer participation, SGIP should cover 100% of project costs, including solar installation costs.

See the Joint CCAs’ Answer to Question 17. As SGIP has not provided incentives for solar PV systems in recent years, the Joint CCAs recommend that SGIP consider DAC-SASH program data for single family customers and SOMAH Program data for multi-family residential customers in order to establish guardrails for total project costs and incentives for solar coupled storage systems.

Question 20: Should additional costs necessary for project installation costs be eligible for SGIP incentives (e.g., panel upgrades, roofing, wiring, etc.)? If so: a. Which costs should be included and why? b. How should these additional costs be accounted for in setting incentive amounts (e.g., incentive adder)?
Joint CCA Answer to Question 20: Residential Equity Budget incentives should cover ancillary project costs as determined by a stakeholder working group.

Based on the Joint CCAs’ experience working with low-income customers over the past several years, low-income customers installing DERs tend to incur unique and often substantial site-specific costs because those customers tend to live in homes that have not been upgraded in a long time. Those costs include, but are not limited to, main electric panel upgrades, fireproofing, laying concrete slabs, and extra wiring. MCE covered these additional project costs for SGIP low-income customers through its own Energy Storage Program and in some cases, encountered 14 additional costs of up to $6,500. In MCE’s experience, if it had not covered those additional costs, most, if not all, of the low-income customers participating in its program would have dropped out.

The Joint CCAs therefore recommend that SGIP cover ancillary project costs for low-income customers to the extent reasonable (for example, a full re-roofing project to accommodate solar panels would not be reasonable). The Joint CCAs recommend that a list of eligible “ancillary project costs” be developed through a stakeholder working group process that includes qualified SGIP installers, and that the list be included in the SGIP Handbook. These ancillary project costs would be part of the total project costs to be reported to the SGIP PAs at the Reservation Request stage and would therefore fall under the cost containment restrictions discussed above.

Topic Area 4.7: Operational Requirements for SGIP and AB 209 Projects Question 29: In addition to requiring higher differential TOU rates, should the Commission require all new SGIP storage incentive and AB 209 recipients to choose and enroll in one of either a supply-side market integrated DR program, or load modifying DR program such as critical peak pricing (CPP)? Why or why not?
Joint CCA Answer to Question 29: The Commission should encourage SGIP participants to participate in demand response (DR) programs but should allow customers the flexibility to choose a DR program that fits their needs, including CCA offerings.

The Joint CCAs recommend that the SGIP PAs encourage SGIP participants to participate in DR programs but do not agree that participants should be required to participate in (or be de-facto auto-enrolled in) any given DR program. In the Joint CCAs’ view, automatic or mandatory enrollment in DR programs does not necessarily lead to effective participation. In fact, DR programs are mostly effective with engaged and informed customers which is not likely if customers are required to enroll in a program they may not support. Furthermore, DR program goals may be at odds with the goals of SGIP, hence complicating participation of customers in both programs simultaneously. For example, SGIP’s goal of GHG reduction may be, at times, at odds with the DR program’s need to reduce load during times of grid stress. 15 The Joint CCAs recommend that the Commission more holistically consider approaches to encourage customers participating in technology incentive programs (such as SGIP) to participate in “performance-focused” energy programs (such as DR programs), and note that the recently initiated DER proceedings (R.22-11-013) may be an opportunity for the Commission to do so.

Nevertheless, if the Commission determines that it is appropriate to require DR program participation for those customers participating in the SGIP, the Joint CCAs urge the Commission to allow customers the flexibility to choose a DR program that meets their needs, including CCA DR programs.16
Topic Area 4.9: Other SGIP Program Changes
Question 36: What administrative tools can the Commission use to streamline the process of making program changes to support effective program implementation? Joint CCA Answer to Question 36: SGIP should modernize and simplify the SGIP portal.

SGIP should provide an online tool to check host customer eligibility via other energy equity Programs.

As described in these comments (and in Appendix A to these comments), over the past several years, the Joint CCAs have helped their customers file SGIP applications and have provided those customers gap funding via their respective Energy Storage Programs. While doing so, the Joint CCAs and their implementation partners have struggled with the antiquated SGIP portal and found that portal to be a hurdle for program participation. The Joint CCAs therefore recommend that the Commission modernize and simplify the SGIP portal. One major upgrade would be to make it easier for customers and their assignees to log into the portal to see the status of the SGIP incentive reservation as well as potential extension requests or other upcoming deadlines. This functionality would streamline the application process and reduce reliance on email 16 Examples include MCE’s Peak FLEXmarket program, SCP’s GridSavvy program; EBCE, MCE, PCE, SCP and SJCE’s FLEXmarket programs.
16 for communication and status updates, thereby reducing workload on developers, applicants, host customers, as well as the SGIP PAs.

In a similar vein, the Joint CCAs recommend that the Commission direct the SGIP PAs to develop and make available an online tool that would allow prospective SGIP applicants (and/or developers) to determine if a host customer is eligible for SGIP based on their participation in other Energy Equity Programs, as discussed above. Such a resource would reduce the significant burden and associated cost of identifying customers eligible to participate in SGIP.

Question 38: Are there any other program improvements suggested? Joint CCA Answer to Question 38:

1. Consider Funding a SGIP Technical Assistance/Incentive Application Support Program
The Joint CCAs recommend that the SGIP PAs dedicate resources to providing increased SGIP technical assistance (TA) and incentive application support to project applicants, developers and host customers. TA and incentive application support is particularly important for low-income customers. In the Joint CCAs’ experience, many smaller installers and developers are reluctant to help customers participate in SGIP—and in some cases, do not even mention the incentive offering to their customers—due to the complexities associated with the SGIP application and enrollment process. Additional support to applicants and developers can mitigate this participation barrier.

A few examples of services that the TA program could provide include:
a. SGIP application office hours – pre-set times where SGIP applicant support staff is available via phone to answer application questions;
b. Expanded bandwidth to answer emails directed to SGIP PAs; c. Record and make publicly available SGIP portal trainings, and; 17 d. Discuss DR program participation or other load management opportunities with system owners and/or host customer.

2. Inclusion of outages caused by EPSS as an eligibility criterion for General Market Resiliency customers
As described above, while the Joint CCAs advocate for the consolidation of SGIP budget categories into two broad categories (Residential Equity Budget and Residential General Market Budget), the Joint CCAs support enhanced incentives for General Market residential customers that reside in areas that are affected by resiliency challenges (including non-low-income vulnerable customers, such as Medical Baseline customers). The Joint CCAs recommend that customers eligible to receive enhanced resiliency incentives include not only those customers facing PSPS events or living in HFTDs, but also customers experiencing “fast trip” outages under PG&E’s EPSS program (which, in recent years, have increased significantly in certain areas within PG&E’s service territory).

While the Joint CCAs do not offer a specific recommendation on a threshold number of EPSS outages that should qualify a customer for an enhanced resiliency incentive (due to the limited data available on EPSS outages), the Joint CCAs recommend that PG&E analyze EPSS data over the past two years to identify a suitable threshold, and propose that threshold in a Handbook update submitted via a Tier 2 Advice Letter to the Commission before AB 209 funding is made available.

3. Promote clarity and consistency in eligibility requirements at program launch and throughout the program’s duration
When the Equity Resiliency budget category was created with the implementation of SB 700, the new Equity Resiliency eligibility criteria were not fully developed at program launch leading to significant customer confusion and project cancellations. The SGIP PAs and the 18 Commission should consider this lesson learned when launching the program with any new program rules implemented at this stage. SGIP should launch with a clear set of criteria and if the criteria changes, it should only be to relax the criteria so that participants are not precluded. If criteria are tightened, those criteria should not apply to any customers who have submitted applications. Finally, there should be a 15-30 day grace period to allow people who are in the process of applying to comply with the new program requirements.

III. CONCLUSION
The Joint CCAs appreciate this opportunity to provide comments on the ACR. In summary, the Joint CCAs make the following specific recommendations:
• The Commission should simplify SGIP residential budget categories to create only two tracks – the Residential General Market Budget ($270 million) and the Residential Equity Budget ($630 million);
• The Commission should tie eligibility for the Residential Equity Budget primarily to eligibility for the California Alternate Rates for Energy Program (CARE) or the Family Electric Rate Assistance Program (FERA) programs;
• The Commission should provide partial upfront payments to project developers/installers after the Reservation Request is approved;
• The Commission should cover 100% of low-income customers’ total system costs in order to drive low-income customer participation in SGIP;
• The Commission should encourage SGIP participants to participate in demand response (DR) programs but should allow customers the flexibility to choose a DR program that fits their needs, including CCA offerings;
• The Commission should modernize and simplify the SGIP portal; • The Commission should provide an online tool to check host customer eligibility via other energy equity programs;
• The Commission should consider funding a SGIP Technical Assistance/Incentive Application Support Program;
• The Commission should include outages caused by EPSS as an eligibility criterion for General Market Resiliency customers, and;
• The Commission should promote clarity and consistency in eligibility requirements at program launch and throughout the program’s duration.
19 Respectfully submitted,
/s/ Nikhil Vijaykar
Nikhil Vijaykar

KEYES & FOX LLP
580 California St., 12th Floor
San Francisco, CA 94104
Telephone: (408) 621-3256
E-mail: [email protected]
On behalf of Joint Community Choice
Aggregators
Dated: December 2, 2022
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APPENDIX A
Joint CCAs’ Energy Storage Programs
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EBCE
EBCE launched its Resilient Homes program in 2020 with the primary goal of providing backup power to single and multifamily residential homeowners facing rolling blackouts or PSPS events.

Under the program, EBCE partners with solar company Sunrun, which assists customers with installing behind-the-meter battery systems and provides an option for financing the systems.

These batteries produce several resilience benefits, including providing customers with energy during outages; coordinating residential battery discharge to the grid during times of peak electricity usage; avoiding expensive infrastructure upgrades; and reducing EBCE’s Resource Adequacy obligation. SGIP is a key incentive utilized to finance the battery systems for low-income customers; additionally, EBCE pre-negotiated with Sunrun to provide standardized prices to customers participating in Resilient Homes and offers further incentives to customers for allowing EBCE to dispatch the batteries. Find more information about the program here.

MCE
MCE launched its Energy Storage Program in July of 2020. The primary goal of the program is to provide resiliency benefits to customers in the face of grid outages such as PSPS events. The program also allows MCE to control the ESS systems to align charging and discharging behavior of energy storage systems (ESS) with grid needs and to reduce demand during times of grid stress.

Under the program, MCE automatically charges participants’ ESS from solar PV, then discharges them every day between 4pm to 9pm. In exchange for agreeing to allow MCE to dispatch the ESS, customers are provided with different types of up-front and performance-based incentives to lower the cost of the ESS. While the MCE Energy Storage Program is available to any MCE generation service customers, the program provides increased incentives and has a participation goal for low-income or other vulnerable customer categories. MCE’s incentives made it possible for low-income customers to get a battery for no out of pocket cost. In 2021, MCE launched a loan program that offers zero and below-market interest rates to customers needing to finance their systems.

PCE
PCE launched its Residential Solar + Storage Program in August of 2020. The primary goal of the program is to provide resiliency benefits to customers in the face of grid outages such as PSPS events. The program also allows PCE to control the energy storage systems (ESS) to align charging and discharging behavior with grid needs, and to reduce demand during times of grid stress. Under the program, PCE automatically charges participants’ ESS from solar PV, then discharges them every day between 4pm to 9pm. In exchange for agreeing to allow PCE to dispatch the ESS, customers are provided with an upfront incentive to lower the cost of the ESS. ---
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SCP
Sonoma Clean Power Authority launched its SGIP Assistance Program in April of 2020. The goal is to help customers affected by PSPS and other outage events take advantage of the state’s generous battery storage incentives. To facilitate incremental SGIP systems, SCP provides customers with 100% of the incentive upfront. Additionally, SCP hired a consultant to assist contractors in submitting SGIP applications. Over 200 applications have been submitted, with over 100 installed and operational. Additional information about the program is available on the SCP website at: Self-Generation Incentive Program (SGIP) Assistance Program.

MCE Board of DirectorsDecember 15, 2022

MCE Board of Directors
December 15, 2022