Executive Committee
March 5, 2026
1:30 PM
Central Coast Community Energy
70 Garden Court, Suite 300
Monterey, CA 93940
REMOTE LOCATION VIA TELECONFERENCE
Any interested parties or community members may attend, and participate in, the meeting at the following addresses where Board members may also join the meeting from:
City of Santa Cruz
City Hall
809 Center Street, Room 10
Santa Cruz, CA 95060
County of San Luis Obispo
Government Building
1055 Monterey Street,
San Luis Obispo, CA 93408
City of Atascadero
City Hall
6500 Palma Ave
Atascadero, CA 93422
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The public may comment on the consent agenda and matters not listed on the agenda but within the Board's jurisdiction at the opening of the meeting. The Board may not take action at this meeting on any item not listed on the Agenda other than to refer the matter to staff or set it for a future meeting. The public may comment on a specific item listed on this agenda when the Board considers that item.
Speakers are limited to 3 minutes each.
In addition, members of the public may request and receive copies without undue delay of any documents that are distributed to the Board, unless there is a specific exemption under the Public Records Act that prevents the disclosure of the record. (Cal. Gov’t Code Section 54957.5) In compliance with Government Code Section 54957.5, non-exempt writings that are distributed to a majority or all of the Board in advance of a meeting and that relate to an agenda item will be made available at 3CE’s offices located at 70 Garden Court, Suite 300, Monterey, CA 93940 during normal business hours and are also available on the 3CE website located at: https://pub-3ce.escribemeetings.com/ REASONABLE ACCOMMODATIONS: In compliance with the Americans with Disabilities Act, any individuals who desire to request a reasonable accommodation or modification to observe or participate in the meeting may make such a request by sending an email to: [email protected] Copies of documents may be made in alternative formats, upon request. Requests for accommodations should be made no later than two (2) business days prior to the meeting to allow time for 3CE to address the request.
DISCLOSURE OF CAMPAIGN CONTRIBUTIONS: Pursuant to Government Code section 84308, members of the Board are disqualified and not able to participate in any agenda item involving contracts (other than competitively bid, labor, or personal employment contracts), franchises, discretionary land use permits and other entitlements if the Board member received more than $250 in campaign contributions from the applicant or contractor, an agent of the applicant or contractor, or any financially interested participant who actively supports or opposes the decision on the agenda item since January 1, 2023. Members of the Board who have received, and applicants, contractors or their agents who have made, campaign contributions totaling more than $250 to a Board member during the proceeding or for 12 months after a final decision is rendered in that proceeding, are required to disclose that fact for the official record of the subject proceeding. Disclosures must include the amount of the campaign contribution and identify the recipient Board member and may be made either in writing to the Clerk of the Board prior to the subject hearing or by verbal disclosure at the time of the hearing.
Welcome & Roll Call
Corrections or Additions
The Clerk will announce agenda corrections or proposed additions of emergency, urgency, or continued items, which will be acted on by the Board as provided in Section 54954.2 of the California Government Code.
CLOSED SESSION
1. CONFERENCE WITH LEGAL COUNSEL Re one matter of significant exposure to litigation pursuant to Government Code Section 54956.9(d)(2).
2. CONFERENCE WITH REAL PROPERTY NEGOTIATORS – Government Code Section 54956.8 Property:
4610 West Walnut Street, Soquel, CA (APN 030-201-78)
Agency negotiator: Robert Shaw and DeWayne Woods
Negotiating parties: Alan Palmer, Palmer Alan Blair Trust Under negotiation: Price and Terms
3. Public Employee Performance Evaluation – Position: Chief Executive Officer-Government Code section 54957
OPEN SESSION
4. Support the Operations Board review and consideration of a 3CE Artificial Intelligence Policy and authorize the Chief Executive Officer to update as necessary to ensure the policy remains contemporary and operationally relevant
5. Receive update on the California Public Utilities Commission’s proceeding to reform the California Climate Credit and provide feedback on recommendations for 3CE’s regulatory engagement Adjournment
Staff Report Item 4
TO: 3CE Executive Committee
FROM: Robert M. Shaw, Chief Executive Officer
PREPARED BY: Emmanuel Gutierrez, Director of Data and IT SUBJECT: Support the Operations Board review and consideration of a 3CE Artificial Intelligence Policy and authorize the Chief Executive Officer to update as necessary to ensure the policy remains contemporary and operationally relevant
DATE: March 5, 2026
RECOMMENDATION:
This memorandum recommendsthat the Executive Committee consider staff’s recommendation to seek the Operations Board’s review and consideration of a 3CE Artificial Intelligence Policy and authorize the Chief Executive Officer to update as necessary to ensure the policy remains contemporary and operationally relevant.
BACKGROUND:
Artificial Intelligence (AI) is rapidly changing the way organizations of all types drive innovation, customer service and efficiency on behalf of their customers and stakeholders. AI tools can provide responsible opportunities for many use cases that would increase the productivity of our employees, and overall service excellence provided to customers:
Rapid analysis of vast amounts of unstructured data, material and information. Complex, predictive, and real-time modeling, forecasting, and management. Rapid and effective customer self-service, using chat-bots and other technology specifically trained on 3CE-specifc publicly available data.
Near real-time document review, preparation, and synthesis. Rapid prototyping and development of internal tools, customer programming, and other applications unique to 3CE.
Given the rapid pace of AI evolution, operational best practices at other CCAs and public agencies has been to adopt an Artificial Intelligence Policy, governing and providing guardrails for employees, contractors, and other stakeholders at 3CE, with the intent of ensuring responsible and safe use of AI, while also unlocking our employees’ ability to embrace the technology to improve day-to-day workflows and tasks.
DISCUSSION/ANALYSIS:
The Attached AI Policy AI Policy provides a structured framework that empowers responsible innovation, protects customer and agency data, and establishes clear governance so AI can be leveraged confidently and compliantly across the organization. Key pillars of the AI Policy include Public Transparency & Trust: Establishes clear ethical standards for AI use that prioritize fairness, accountability, and human oversight. Protects customer data, sensitive information, and regulatory compliance to maintain public confidence. Communications and Clarity: Defines what AI is, who may use it, and what “Responsible Use” requires. Provides staff, vendors, and contractors with clear rules so AI adoption is thoughtful, consistent, and aligned with 3CE’s mission. Internal Alignment and Accountability: Assigns clear ownership for AI systems, including required human oversight and designated bot owners. Clarifies the roles of Data & IT, departments, and General Counsel in governance and compliance. Governance and Oversight: Requires training, structured tool approval, documentation, audits, security standards, and ongoing monitoring. Ensures AI use is reviewed, approved, and continuously evaluated rather than used informally or inconsistently. Identification of Risks and Responsible Innovation: Encourages productivity, customer programming, modeling, use of energy management systems and other innovation while prohibiting harmful, deceptive, biased, or unlawful uses. Creates structured guardrails so 3CE can leverage AI safely.
FISCAL IMPACT:
There are no immediate fiscal impacts associated with adopting the attached 3CE AI Policy all costs to contract for AI access will be absorbed withing the current budget.
CONCLUSION:
Supporting the Operations Board’s consideration of the AI Policy can support 3CE operations by encouraging responsible, safe and secure use of AI technology will enable 3CE to drive innovation and value for customers, while at the same time increasing productivity and efficiency in operations.
ATTACHMENT(S):
1. DRAFT 3CE AI Policy
Central Coast Community Energy Artificial Intelligence Policy I. Purpose and Scope:
a) This Policy establishes standards that Central Coast Community Energy staff, consultants, vendors, and contractors, shall adhere to ensure the responsible and secure use of artificial intelligence (AI) to serve our customers. AI presents the potential to enhance the productivity, efficiency, creativity and innovation of 3CE operations, for the benefit of our customers.
b) This Policy enables the responsible use of AI tools to improve service delivery, while protecting integrity, security, privacy, regulatory compliance, and mitigating risks. 3CE seeks to ensure responsible, ethical, fair, and compliant use of this technology.
II. Definitions:
a) Artificial Intelligence (AI): A machine-based system that, for explicit or implicit objectives, infers from the input it receives, how to generate outputs (predictions, content, recommendations, or decisions) that can influence physical or virtual environments with varying autonomy or adaptiveness.
b) AI Tools: any app, software, or system that utilizes Artificial Intelligence (including Generative AI), machine learning, or other advanced algorithms. c) Generative AI (GenAI): GenAI is a subset of artificial intelligence that can generate new content and may do so autonomously, such as text, images, videos, audio, and code, in response to a user's prompt. “Bots” are a form of GenAI. d) Sensitive Data: Information that requires additional protection due to its confidential or personal nature, including but not limited to: health records or medical information; financial information, Personally Identifiable Information (PII) such as social security numbers, addresses, financial account information, utility account information, dates of birth, driver’s license numbers, or any government-issued identifiers; proprietary or trade secret information; information protected by attorney-Page 4 of 84 client privilege or attorney work product; information designated as confidential pursuant to any other Agency or Regulator having jurisdiction. e) AI users: AI users include employees, volunteers, interns, contractors, sub-contractors, vendors, or bots doing work on behalf of or for the Agency, each of which must have a designated human owner accountable for its use and outputs. f) Responsible use: Responsible Use requires AI users emphasize:
i. The ethical, transparent, and accountable development, deployment, and ongoing management of AI and AI Tools.
ii. Ensuring the use of AI and AI Tools align with human values and legal standards while promoting fairness, inclusivity, and non-discrimination. iii. Utilizing due diligence in reviewing all results for accuracy, completeness, and context. AI users must ensure human oversight, explainability, privacy protection, and exercise continuous monitoring to mitigate risks and unintended consequences.
iv. AI users are responsible and accountable for verifying the accuracy of any AI-generated content.
III. Guiding Principles
a) 3CE supports and promotes the Responsible Use of AI to:
i. Assist, empower, and inspire Central Coast residents to be a 3CE customer. ii. Meaningfully advance the deployment of renewable energy generation, energy storage, and innovative technologies to provide 3CE customers with clean and reliable electricity at the lowest possible cost.
iii. Develop, review, and implement programs, energy management systems, and new business lines that support 3CE’s mission.
iv. Forecast, model, and analyze risks to 3CE’s core business functions.
v. Solving problems, reducing barriers to service, and measuring tangible outcomes of 3CE service.
b) Training: All employees with access to approved AI tools must complete required AI Responsible Use training upon onboarding and periodically thereafter, as determined by the Data and IT Department.
c) Human Involvement: A 3CE human employee will be involved in reviewing AI-generated work before it is considered final.
IV. Prohibited Uses of AI Tools and Activities
a) The following uses of AI Tools are prohibited:
i. Using AI or AI tools in a manner that does not comply with Responsible Use standards or 3CE’s Guiding Principles to make decisions requiring human judgment or authorization.
ii. Any use of AI Tools for malicious, deceptive, fraudulent, or otherwise intentionally harmful purposes is strictly prohibited.
iii. Circumventing security controls or data protection measures. iv. Violating law, including those laws protecting intellectual property rights or personal privacy.
v. Engaging in activities that could harm the Agency’s reputation or public trust. vi. Utilizing AI to record or summarize meetings without the consent of all participants.
vii. Utilizing AI to make employment decisions about applicants or employees, including recruitment, hiring, retention, promotions, transfers, performance monitoring, discipline, demotion, or terminations without prior IT approval of the AI tool or LLM.
b) Employees are further prohibited from:
i. Upload confidential, proprietary, or sensitive information into any AI tool.
Examples include passwords, credentials, customer data, or personnel information.
ii. Integrating AI tools with internal Agency software without prior IT approval is prohibited. All integration requests must follow the IT Department’s review and approval workflow.
V. Roles and Responsibilities
a) All AI users are responsible for following this Policy and ensuring the Responsible use of AI, AI Tools and/or Generative AI technologies.
b) All AI users are responsible for the product produced, regardless of the utilization of AI, AI Tools, or Generative AI technologies.
c) The Data and IT department will provide technical guidance, standards, and oversight to support the Agency’s responsible use of AI in alignment with this Policy. d) Departments are responsible for ensuring their staff’s compliance and training related to their specific use cases.
e) Director of Data and IT is responsible for overseeing the enterprise security infrastructure, updating security policies, procedures, standards, guidelines, and monitoring Policy compliance.
f) The Director of Data and IT is responsible for overseeing digital privacy practices, ethics, data processing practices, and responsible for the use of technology. g) The Data and IT Department may, at its discretion, inspect the usage of AI systems and require a department to alter or cease its usage of AI systems. h) AI bots, automated agents, or autonomous workflows deployed on behalf of 3CE must have a designated human owner who is responsible for obtaining required approvals, monitoring performance, reviewing outputs, and ensuring ongoing compliance with this Policy.
VI. Data Privacy and Security
Data privacy and security are paramount when utilizing AI tools, whether using an agency-issued device or a personal device including a personal computer, tablet, or cellphone.
a) Data and IT will maintain a list of approved AI tools that have undergone security and privacy reviews. Employees shall confirm that the vendor/tool is approved and consult with the IT Department before using any new AI tools. b) Data and IT will, as necessary, conduct audits and maintain necessary records to ensure the use of AI, AI Tools, and Generative AI avoid algorithmic bias. c) AI tools used for Agency business should be reviewed and approved by the Data and IT Department to ensure alignment with security, privacy, and procurement standards.
d) Enterprise licensing will be coordinated where appropriate to promote consistency, data protection, and cost efficiency. Use of personal or unapproved AI accounts for Agency business requires prior review and approval from the Data and IT department.
e) Contracts with AI service providers must address, at a minimum, the following:
i. Data privacy and security protection.
ii. Prohibition on using agency data for model training without written consent. iii. Data retention and deletion protocols.
iv. Audit rights and transparency.
VII. Reporting Procedures and Violations
a) Violating this Policy may result in disciplinary action, up to and including termination.
b) Employees and AI users are expected to provide notice to their immediate supervisor and/or any Manager, Director, or Officer immediately if they become aware of:
i. An actual or possible violation of this Policy.
ii. A breach of data privacy or security.
iii. Failure or a circumstance where an AI tool is generating output which is erroneous, incomplete, misleading, offensive, harassing, or discriminatory and causes an AI user to have concerns or which otherwise violates Agency Policies. iv. Any other use of AI tools that may reasonably pose legal, ethical, security, or reputational risk to the Agency.
VIII. Annual Reviews / Updates
AI technology and applicable laws and regulations are rapidly evolving. This Policy will be reviewed at least annually by the Chief Executive Officer or designee and updated as necessary as authorized by the Chief Executive Officer.
IX. Related Standards and Policies
3CE Privacy Policy
3CE IT Policies
Effective Date:
Approved by:
Staff Report Item 5
TO: 3CE Operations Board of Directors
FROM: Robert M. Shaw, CEO
PREPARED BY Jerri Strickland, Director of Regulatory Affairs & Compliance Robert Wool, Policy Advisor
SUBJECT: Receive update on the California Public Utilities Commission’s proceeding to reform the California Climate Credit and provide feedback on recommendations for 3CE’s regulatory engagement
DATE: March 5, 2026
RECOMMENDATION:
Receive update on the California Public Utilities Commission’s proceeding to reform the California Climate Credit and provide feedback on recommendations for 3CE’s regulatory engagement.
BACKGROUND:
The California Climate Credit (CCC) is funded by the State’s greenhouse gas (GHG) emissions program, Cap-and-Invest, which requires large emitters to retire allowances equal to their emissions. To protect ratepayers from Cap-and-Invest Program compliance costs, the California Air Resources Board (CARB) allocates free allowances to the Utilities on behalf of their ratepayers. The utilities must consign these allowances to state-run auctions, and the resulting sales proceeds are then returned to Californians as the Climate Credit.
Under the current California Public Utilities Commission (CPUC) framework, the resulting credits are delivered in a twice-per-year lump-sum bill credit provided to all bundled and unbundled residential customers and certain qualifying small business customers in April and October. Credit allotments are independent of electricity usage; all residential or eligible small business accounts receive a flat credit amount based on which IOU service area they are located.
On July 24, 2025, the CPUC approved the Order Instituting Rulemaking (OIR), Rulemaking (R). 25-07- 013, to consider ways to improve the effectiveness of the Climate Credit in supporting affordability. This
proceeding also addresses new provisions created by Assembly Bill (AB) 1207 which allow credits to be provided in no more than four high-billed months of each year to maximize customer affordability.
On February 3, 2026, the CPUC issued the scoping ruling establishing the priorities for Phase 1A of the proceeding. In order for a decision to be implemented into 2026 billing cycles, this phase will consider pausing the 2026 residential credit and other immediate affordability improvements. While Phase 1B will take broader considerations to evaluate climate credit eligibility, distribution timing, and calculation methodologies. Phase 2 will be addressed at a later date and is expected to include other issues related to the utilities’ allowance revenues as well as implementation of changes in CARB’s regulations. CARB recently issued a public hearing on proposed changes to prohibitions on how the utilities are allowed to distribute the credits.
As the state considers thematic changes to implementation of the Climate Credit, it could alter the value of the credit to 3CE customers.
DISCUSSION/ANALYSIS:
The large electric utilities forecast their CCC allowance revenues in annual Energy Resource Recovery Account (ERRA) Forecast applications. The Commission adopted the IOU’s proposed 2026 California Climate Credit of $36.18; this credit value is 37.9 percent lower than the year before, which was $58.23. Based on the estimated number of small commercial and residential customers in 2026, SCE proposed a $36 credit amount.
Under the current credit distribution framework, the approximately 407,000 3CE residential accounts in PG&E’s service territory will receive over $29 million in credits while approximately 37,000 3CE residential accounts in SCE’s service territory will receive around $2.6 million.However, changes to how the credit will be distributed could reduce the number of 3CE customers eligible to receive the credit in 2026.
Themes from the CPUC OIR and scoping ruling raise new questions that have not yet had to be considered and may impact affordability for 3CE’s customers:
1. Adjustments to the timing and number of Climate Credit distributions a. The Commission could modify the current bi-annual distribution schedule of April and October to allow distribution in up to four high-billed months per year. The electric CCC distribution schedule could also be modified to better align with high-usage periods within individual LSEs service territory. Aligning the credits to support customers during peak demand and distributing payments over longer periods could increase customer
benefit and mitigate month-to-month bill volatility.
Staff Recommendation: 3CE’s highest billing months for residential customers are in January and February. Advocating for credit distribution during these months would help reduce peak monthly bills for 3CE customers.
2. Reallocation of the Residential California Climate Credit to Low-Income Customers a. The Commission will consider immediate changes to the residential credit to maximize affordability. The Commission’s Report Responding to Executive Order N-5-24 published in February 2025 proposed options such as limiting eligibility for the electric Climate Credit to customers enrolled in affordability programs such as the California Alternate Rates for Energy (CARE) and Family Electric Rate Assistance Program (FERA). CARE and FERA are state programs to provide financial relief on electricity bills for income-qualified households.1 Staff Recommendation: Currently, only 18% of 3CE customers are enrolled in CARE or FERA. Limiting the credit exclusively to CARE and FERA participants could increase the benefit provided to those customers but would reduce the total amount of credit distributed across 3CE’s service area. 3CE should advocate that all customers are impacted by rising, climate-driven costs and should receive a credit to help address affordability challenges associated with climate change. In addition, FERA is widely recognized as an underutilized program, particularly among minority and underserved communities. Both SCE and PG&E report that only 15% of eligible customers are currently enrolled in FERA, while CARE enrollment exceeds 95%.23
3. Reallocation of the Residential CCC to Customers living in Warm Climate Zones a. The Commission will consider potentially broad changes to credit distribution, including proposals to limit eligibility to customers residing in warm climate zones, who may experience higher bills due to increased cooling needs.
Staff Recommendation: Although climate zones have not yet been clearly defined, 3CE’s primarily coastal service territory would most likely not be classified as a “warm climate zone.” Staff recommends 3CE advocate that all customers experience increased costs due to climate change. Limiting credit
1 California Public Utilities Commission. (n.d.). CARE/FERA Program. Retrieved February 7, 2026, from https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/care-fera-program 2 Pacific Gas and Electric Company. (2025). ESA, CARE and FERA Programs 2024 Annual Report (Corrected). https://liob.cpuc.ca.gov/wp-content/uploads/sites/14/2025/10/PGE-ESA-CARE-Annual-Report_Corrected.pdf 3 Southern California Edison Company. (2025). ESA, CARE 2024 Low-Income Annual Report (Revised). https://liob.cpuc.ca.gov/wp-content/uploads/sites/14/2025/10/SCE-ESA-CARE-2024-Low-Income-Annual-Report_Revised.pdf
eligibility to customers in inland warm climate zones could result in no 3CE customers being eligible for the credit.
4. Transitioning from a flat credit to volumetric credit a. Currently, the CCC is based upon an equal distribution of the IOU’s proceeds resulting from the Cap-and-Trade auction. Shifting to a volumetric amount would result in customers receiving a credit based on usage. Customers with a higher usage in the month of distribution would receive a higher credit than customers with a lower usage.
Staff Recommendation: Advocate for a CCC structure that supports electrification and load flexibility rather than rewarding higher consumption. A volumetric credit based solely on monthly usage may discourage investments in energy efficiency, battery storage, and demand response, as customers who actively manage or reduce grid usage would receive a lower credit. Maintaining a flat credit or adopting an approach that accounts for load shifting and distributed energy resources, better aligns the CCC with California’s decarbonization goals and provides broader benefits to Californians facing climate change-related cost impacts.
PROCEEDING SCHEDULE:
Immediate changes and a determination on whether or not to pause the 2026 Climate Credit will be determined as early as a March 19, 2026 CPUC Voting Meeting. Additional changes will be considered again by an April 30, 2026 CPUC Voting meeting. Additional phases of the proceeding will continue into 2027.
FISCAL IMPACT:
Changes to the CCC would not have a direct fiscal impact on 3CE. However, changes to the allocation methodology and eligibility impact affordability for 3CE customers.
CONCLUSION:
The Executive Committee’s consideration and feedback will inform staff’s advocacy position on reform of the CCC with CalCCA and at the CPUC.
ATTACHMENT(S):
CPUC Order Instituting Rulemaking to Improve the California Climate Credit (OIR) R.25-07-013 CPUC Response to Executive Order N-5-24
CPUC Assigned Commissioner’s Scoping Memo and Ruling
574655670 - 1 -
ALJ/SW9/jnf Date of Issuance 7/28/2025
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking to
Improve the California Climate
Credit.
FILED
PUBLIC UTILITIES COMMISSION
JULY 24, 2025
SAN FRANCISCO, CA
RULEMAKING 25-07-013
ORDER INSTITUTING RULEMAKING TO
IMPROVE THE CALIFORNIA CLIMATE CREDIT
Summary
This rulemaking is initiated to consider ways to improve the effectiveness of the California Climate Credit for supporting customer affordability and implementation of the California Industry Assistance to minimize leakage of emissions. Parties may file comments on the preliminary scope and schedule established in this rulemaking according to the schedule set forth in Section 5 below.
1. Background
The California Cap-and-Trade Program requires power plants, fuel providers, and large industrial facilities that emit greenhouse gases to retire allowances or a limited quantity of offsets equal to their greenhouse gas emissions. Sale of compliance allowances generates proceeds that are used to benefit Californians. Investor-owned utilities are allocated allowances annually under the Cap-and-Trade Program, which must be sold each year at quarterly California Air Resources Board (CARB) auctions.
R.25-07-013 ALJ/SW9/jnf
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In accordance with Public Utilities (Pub. Util.) Code Section 748.5, proceeds from the electric allocated allowances are used to benefit residential, small business, emission-intensive trade-exposed (EITE) customers and fund certain clean energy and efficiency programs. Per Commission decisions in Rulemaking (R.) 11-03-012 and R.20-05-002, the California Climate Credit (Climate Credit) is delivered as a twice-per-year lump-sum bill credit automatically provided to all bundled and unbundled residential electric customers and certain qualifying small business electric customers. Qualifying EITE industrial customers receive California Industry Assistance annually from the same Cap-and-Trade Program funds.
Natural gas investor-owned utilities are not subject to Pub. Util. Code Section 748.5; Commission decisions in R.14-03-003 determined that all proceeds not used for programs should be distributed annually and split equally among all residential customers as a Climate Credit on gas bills once per year.
Since 2014, customers of California electric and gas investor-owned utilities have received over $17.8 billion dollars of bill assistance through the Cap-and-Trade Program. In 2025, the electric residential Climate Credit will total $1.41 billion (a weighted average of $120 per customer and a range of $70-$519 per customer), with another $122 million for small businesses and $104 million for EITE industrial customers. In 2025, residential gas customers will receive a total of $994 million (a weighted average of $76 per customer and a range of $54- $87 per customer). Proceeds will continue to be available to electric and natural gas customers through at least 2030 but fluctuate from year to year depending on auction proceeds; the legislature is currently considering extension of the Cap-Page 15 of 84 R.25-07-013 ALJ/SW9/jnf
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and-Trade Program past 2030 which could extend these ratepayer benefits even further.
This rulemaking will explore potential approaches to maximize the effectiveness of Cap-and-Trade Program proceeds for supporting customer affordability.
1.1. Eligibility for the Climate Credit
Pub. Util. Code Section 748.5 lists the types of customers eligible for receiving distribution of Cap-and-Trade Program proceeds, and the Commission has defined eligibility among those customers in previous decisions. Adjusting eligibility criteria can increase the impact of the bill assistance provided by the credits. For example, Resolution E-5339 limited small business customer eligibility for the Climate Credit to electric customers with less than 100 individually eligible accounts, providing a larger annual credit for eligible customers.
Another approach would be to limit eligibility to certain customer groups.
The Commission’s Report Responding to Executive Order N-5-24 published in February 2025 proposed options such as, for example, limiting eligibility for the electric Climate Credit to customers enrolled in the California Alternate Rates for Energy (CARE) or Family Electric Rate Assistance Program (FERA) programs, or to customers in hot climate zones.
1.2. Distributing Climate Credit Funds
Currently, residential and qualifying small business electric customers receive the Climate Credit twice per year in a lump sum amount per customer
R.25-07-013 ALJ/SW9/jnf
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account each April and October. Residential gas customers receive the Climate Credit once per year as a lump sum per-account amount each April.
The Commission could adjust the number of distributions or time-of-year of distributions to increase the effectiveness of the electric or natural gas Climate Credit for addressing affordability issues. Alternatively, the electric Climate Credit could be allocated on the basis of usage, reducing the volumetric rate for electricity. This approach could potentially accelerate decarbonization of homes and businesses by making electrification more appealing to ratepayers and could reduce month-to-month bill volatility. Additional options for distributing proceeds could also be considered, such as increasing the portion of residential Climate Credit funds distributed to CARE and FERA customers. Any change to the distribution of Climate Credit funds should be consistent with CARB’s Cap-and-Trade regulations.
1.3. Education and Outreach about the Climate Credit
The Climate Credit is a direct way California households and businesses benefit from the Cap-and-Trade Program. Education and outreach costs are paid for out of the Climate Credit, reducing financial benefits to customers. Since 2013, administrative, education, and outreach costs amounted to $23.6M, or less than 0.1% of total Cap-and-Trade Program proceeds. Adding education and outreach requirements about changes to the allocation or distribution of the Climate Credit could help customers better understand their electric bills but would come at a cost to households and businesses.
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1.4. California Industry Assistance
California Industry Assistance offsets a portion of the cost of the Cap-and-Trade Program built into electric prices. California-made products include the cost of greenhouse gas emissions, while imported goods from out-of-state manufacturers typically do not. CARB annually allocates allowances to industrial facilities covered by the Cap-and-Trade Program to minimize emissions leakage while preserving incentives to maintain efficient production within California.
Emissions leakage can occur when production moves out-of-state, so there appears to be a reduction in California’s greenhouse gas emissions, but the production and emissions have been simply relocated. Program implementation includes use of the North American Industry Classification System (NAICS) code already used by California businesses for tax and other business purposes that reflects the type of good produced.
2. Preliminary Scoping Memo
The preliminary scope of issues in this Order Instituting Rulemaking (OIR) is set forth below, in accordance with the Commission’s Rules of Practice and Procedure (Rules), Rule 7.1(d).
a. Should the Commission modify electric and natural gas Climate Credit eligibility criteria for residential and small business customers?
b. Should the Commission modify implementation of the
California Industry Assistance for EITE customers?
c. How and when should Cap-and-Trade proceeds be
distributed to eligible residential, small business, and EITE customers each year?
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d. If changes are made to the Climate Credit allocation or distribution, how should these changes be communicated
to customers?
3. Opportunity for Comments
The Commission invites party comment on the Preliminary Scoping Memo and issues identified in this document. Party comments may also address:
Whether there are additional issues that should be
included in the scope of this proceeding;
The preliminary schedule and appropriate prioritization or sequencing of topics and activities that should be handled in this proceeding leading to Commission decision(s);
Any objections to the preliminary determinations;
Any specific issues previously addressed or already
underway in other Commission proceedings that require
coordination with this rulemaking.
Commenting parties shall file comments within 60 days after the issuance date of this OIR. Reply comments shall be filed within 15 days after the final date to file comments. The Commission will use parties’ comments to identify areas that need clarification and may consider the addition of specific issues or questions related to the items described in Section 2 on the scope of this proceeding.
4. Categorization and Need for Hearing
Rule 7.1(d) requires that an OIR preliminarily determine the category of the proceeding and the need for a hearing. We preliminarily determine that this proceeding is quasi-legislative as defined in Rule 1.3(g). This determination is not appealable, but shall be confirmed or changed via ruling by the assigned
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Commissioner. The assigned Commissioner’s determination as to category is subject to appeal pursuant to Rules 7.3 and 7.6.
We anticipate that the issues in this proceeding may be resolved through a combination of filed comments and workshop(s), and that evidentiary hearings will not be necessary. Any person who objects to the preliminary hearing determination shall state the objections in their comments on this OIR. The assigned Commissioner will determine the need for hearing in the scoping ruling issued following a prehearing conference.
5. Preliminary Schedule
The preliminary schedule for the OIR is summarized below. The schedule may be revised by the assigned Commissioner or the assigned Administrative Law Judge (ALJ) to develop an adequate record, provide due process, and conduct this proceeding in an orderly and efficient manner. Parties may comment on the preliminary schedule, in addition to identifying a need for, and date for, any additional events such as workshops.
Event Date
Comments on OIR 60 days after OIR issuance
Reply comments on OIR 15 days after comments
Prehearing conference Within 30 days after reply comments filed Scoping memo and ruling Within 60 days after reply comments filed The assigned Commissioner or the assigned ALJ may change or modify the schedule to promote efficient and fair administration of this proceeding.
Today’s decision sets a due date for comments and reply comments on the OIR.
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The schedule for the remainder of the proceeding will be adopted in the assigned Commissioner’s Scoping Memo and Ruling.
It is the Commission’s intent to complete this proceeding within 18 months of the date this decision is adopted (Section 1701.5(b)).
If there are any workshops in this proceeding, notice of such workshops will be posted on the Commission’s Daily Calendar to inform the public that a decision-maker or an advisor may be present at those meetings or workshops.
Parties shall check the Daily Calendar regularly for such notices.
6. Respondents
Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), San Diego Gas & Electric Company (SDG&E), Southern California Gas Company, Southwest Gas Company, Liberty Utilities (CalPeco Electric), Bear Valley Electric Service, and PacifiCorp are named as respondents to this proceeding.
7. Service of OIR
We provide service to all core transport agents and to the service lists of the following proceedings:
Rulemaking (R.) 14-03-003 (Natural Gas Utility Cost Issues Associated with Greenhouse Gas Emissions);
R.22-07-005 (Demand Flexibility Rates);
R.20-05-002 (Climate Credits);
R.14-07-002 (Net Energy Metering);
Application (A.) 24-09-014 (PG&E General Rate Case Phase 2);
A.24-03-019 (SCE General Rate Case Phase 2);
A.23-01-008 (SDG&E General Rate Case Phase 2);
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R.18-07-005 (Residential Disconnections);
A.24-09-001 (Southwest Gas Company General Rate Case); A.24-09-010 (Liberty Utilities General Rate Case);
A.22-08-010 (Bear Valley Electric Service General Rate Case); and
A.22-05-006 (PacifiCorp General Rate Case).
Service of the OIR does not confer party status or place any person who has received such service on the official service list for this proceeding.
Instructions for obtaining party status or being placed on the official service list are given below.
8. Addition to Official Service List and
Subscription Service
Addition to the official service list is governed by Rule 1.9(f). Upon request, any person will be added to the “Information Only” category of the official service list. Any person intending to make such a request should do so promptly in order to ensure timely electronic service of all comments and other documents and correspondence in the proceeding. (See Rule 1.9(f).) The request must be sent to the Process Office at [email protected]) or letter (Process Office, California Public Utilities Commission, 505 Van Ness Avenue, San Francisco, California 94102). Please include the Docket Number of this rulemaking in the request.
Persons who file responsive comments to this OIR will automatically become parties to the proceeding (see Rule 1.4(a)(2)) and will be added to the “Parties” category of the official service list upon such filing.
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In order to assure service of comments and other documents and correspondence in advance of obtaining party status, persons should promptly request addition to the “Information Only” category as described above; they will be removed from that category upon obtaining party status.
Persons may monitor the proceeding by subscribing to receive electronic copies of documents in this proceeding that are published on the Commission’s website. There is no need to be on the official service list in order to use the subscription service. Instructions for enrolling in the subscription service are available on the Commission’s website at http://subscribecpuc.cpuc.ca.gov/.
9. Filing and Service of Comments and
Other Documents
Filing and service of comments and other documents in the proceeding are governed by the Commission’s Rules. Parties are instructed to only serve documents on the assigned Commissioner, advisors to the assigned Commissioner, and the assigned ALJ by electronic copy and not by paper copy, unless specifically instructed to do otherwise.
When serving any document, each party must ensure that it is using the current official service list on the Commission’s website.
Persons who are not parties but wish to receive electronic service of documents filed in the proceeding may contact the Process Office at [email protected] to request addition to the “Information Only” category of the official service list pursuant to Rule 1.9(f).
The Commission encourages those who seek information-only status on the service list to consider the Commission’s subscription service as an alternative. The subscription service sends individual notifications to each
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subscriber of formal e-filings tendered and accepted by the Commission. Notices sent through subscription service are less likely to be flagged by spam or other filters. Notifications can be for a specific proceeding, a range of documents and daily or weekly digests.
10. Intervenor Compensation
Intervenor compensation is permitted in this proceeding. Pursuant to Section 1804(a)(1), a customer who intends to seek an award of compensation must file and serve a notice of intent to claim compensation within 30 days after the prehearing conference. Parties new to participation in Commission proceedings may contact the Commission’s Public Advisor’s Office (Public Advisor) for further guidance.
11. Public Advisor
Any person interested in participating in this proceeding who is unfamiliar with the Commission’s procedures or has questions about the electronic filing procedures is encouraged to obtain more information at https://www.cpuc.ca.gov/about-cpuc/divisions/news-and-public-information-office/public-advisors-office%20 or contact the Commission’s Public Advisor at 1-866-849-8390 or 1-866-836-7825 (TTY), or send an e-mail to [email protected].
O R D E R
IT IS ORDERED that:
1. This Order Instituting Rulemaking is adopted pursuant to Rule 6.1 of the Commission’s Rules of Practice and Procedure.
2. The preliminary categorization is quasi-legislative.
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3. The preliminary determination is that hearings are not needed.
4. The preliminary scope of issues is as stated in Section 2 of this Order Instituting Rulemaking.
5. The preliminary schedule stated in Section 5 of this Order Instituting Rulemaking is adopted.
6. Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, Southern California Gas Company, Southwest Gas Company, Liberty Utilities (CalPeco Electric), Bear Valley Electric Service, and PacifiCorp are respondents to this Order Instituting Rulemaking.
7. Any person may file comments responding to this Order Instituting Rulemaking within 60 days of the issuance date of this order. Reply comments shall be filed within 15 days after the final date to file comments.
8. The Executive Director will cause this Order Instituting Rulemaking to be served on all respondents, all core transport agents, and to the service lists of the following Commission proceedings:
Rulemaking (R.) 14-03-003 (Natural Gas Utility Cost Issues Associated with Greenhouse Gas Emissions);
R.22-07-005 (Demand Flexibility Rates);
R.20-05-002 (Climate Credits);
R.14-07-002 (Net Energy Metering);
Application (A.) 24-09-014 (Pacific Gas and Electric
Company General Rate Case Phase 2);
A.24-03-019 (Southern California Edison Company General Rate Case Phase 2);
A.23-01-008 (San Diego Gas & Electric Company General Rate Case Phase 2);
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R.18-07-005 (Residential Disconnections);
A.24-09-001 (Southwest Gas Company General Rate Case); A.24-09-010 (Liberty Utilities General Rate Case);
A.22-08-010 (Bear Valley Electric Service General Rate Case); and
A.22-05-006 (PacifiCorp General Rate Case).
9. Any party that expects to claim intervenor compensation for its participation in this rulemaking must file its notice of intent to claim intervenor compensation within 30 days of the prehearing conference.
This order is effective today.
Dated July 24, 2025, at San Francisco, California.
ALICE REYNOLDS
President
DARCIE L. HOUCK
JOHN REYNOLDS
KAREN DOUGLAS
MATTHEW BAKER
Commissioners
CPUC Response to
Executive Order N-5-24
February 18, 2025
Thanks to:
Jenny Au, Simon Baker, Aaron Bloom, Adam Banasiak, Dan Buch, Adam Buchholz, Dan Bout, Tory Francisco, Justin Galle, Brooke-Sydney Harbour, Jenneille Hsu, Coby Jacob, Ankit Jain, Forest Kaser, Kapil Kulkarni, Cheryl Lee, Regina Momblanco, Candace Morey, April Mulqueen, Rachel Peterson, Erica Petrofsky, Bridget Sieren-Smith, Jean Spencer, Jeorge Tagnipes, Leuwam Tesfai, Chris Westling, Nick Zanjani
Contents
PREFACE .................................................................................................... 1 INTRODUCTION: CLEAN ENERGY SUCCESS IS THREATENED BY RATE IMPACTS 3 California’s Climate Goals in the Energy Sector: A Success Made Possible by Utility Ratepayers........................................................................................................... 3 Today’s Electricity Rates Trajectory..................................................................... 6 What is Cost Effectiveness, and How Does it Affect Rates? ............................... 8 SECTION 1 - RESPONSE TO EXECUTIVE ORDER REQUEST TO REVIEW PROGRAMS .............................................................................................. 14 SECTION 2 – RESPONSE TO EXECUTIVE ORDER REQUEST TO CONSIDER WAYS TO IMPROVE THE EFFECTIVENESS OF THE CALIFORNIA CLIMATE CREDIT ...... 19 SECTION 3 - RESPONSE TO EXECUTIVE ORDER REQUEST TO RECOMMEND WAYS TO REDUCE WILDFIRE MITIGATION COSTS......................................... 22 SECTION 4 – RESPONSE TO EXECUTIVE ORDER REQUEST TO PURSUE FEDERAL FUNDING OPPORTUNITIES .......................................................................... 27 APPENDIX ................................................................................................. 28
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Preface
The California Public Utilities Commission (CPUC) appreciates the opportunity to respond to Governor Newsom’s Executive Order N-5-24. The Governor’s Executive Order sets forth an imperative to mitigate the rising costs of electricity service in California. The CPUC shares this sense of urgency and resolve. In the CPUC’s annual SB 695 Report, the CPUC provides an analysis of rates and forecasts of rate trends, and for several years has taken actions within the CPUC’s authority to mitigate rising costs for ratepayers.
Executive Order N-5-24 requests the CPUC to:
• Examine the benefits and costs to electric ratepayers of programs it oversees and rules and orders it has promulgated pursuant to statutory mandates that may be unduly adding to electric rates, or whose funding might more appropriately come from a source other than ratepayers.
Report to Governor Newsom by January 1, 2025, the results of its analysis and its recommendations for modifying or repealing any statute that would reduce costs to electric ratepayers without compromising public health and safety, electric grid reliability, or the achievement of the State's 2045 clean electricity goal and the State's 2045 economywide carbon neutrality goal.
• Take immediate action under existing authorities to modify or sunset any underperforming or underutilized programs or orders whose costs exceed the value and benefits to electric ratepayers. The commission is requested to return any unused funds collected from ratepayers for underperforming programs and utility investments in the form of a bill credit, if it identifies such funds.
• Consult with California Air Resources Board on options to maximize the effectiveness of California's Climate Credit-which returned an average of $71 to electric ratepayers on their utility bills this fall.
Options to improve the credit, particularly for low-income Californians, should be reported to me by January 1, 2025.
• Consult with the Office of Energy Infrastructure Safety on adjustments to utility wildfire safety oversight processes, procedures, and practices that would yield administrative efficiencies and focus utility investments and activities on cost-effective wildfire mitigation measures that reduce wildfire ignition risk while managing costs to electric ratepayers.
Proposals for legislative or regulatory changes should be reported to me by January 1, 2025.
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• Pursue, and direct the regulated utilities to pursue, all federal funding opportunities that can help reduce and avoid electric service costs that would otherwise flow into electric ratepayer bills.
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Introduction: Affordability and
Clean Energy Success Is
Threatened by Rate Impacts
California’s Climate Goals in the Energy Sector: A Success Made Possible by Utility Ratepayers
California’s climate goals have clean energy as a centerpiece. From 2002 when the state adopted its first Renewables Portfolio Standard (RPS) requirement, utility ratepayers have funded major clean energy achievements. The vision for economywide carbon neutrality is now set forth in the California Air Resources Board’s Climate Change Scoping Plan, and the electricity sector is on track to achieve greenhouse gas emissions reductions to achieve the ambitious goal of carbon neutrality by 2045.
The California Constitution and the Public Utilities Code spell out how utility customers have funded this success. The Legislature directs the CPUC, who in turn directs the retail electricity providers (load serving entities) to purchase utility-scale least-cost, best fit clean electricity resources on behalf of their customers. This structure has resulted in cost-competitive clean energy achievements that lead the world.
All new procurement today is emissions-free. What’s more, prices for solar, wind, and battery storage that are shared among customers on our interconnected bulk system are decreasing every year.
This is the ratepayer funded clean energy success story of California.
At the same time, California’s transportation, buildings and industrial sectors are transitioning away from fossil fuel-supplied energy sources. Electricity is already playing a larger role in powering the economy and addressing the climate crisis demands further expansion of electrification.
However, as the Governor’s Executive Order recognizes, electricity ratepayers are now experiencing rising bills due to a number of factors, including the impacts of climate change, and many Californians are struggling to bear the burden of increased costs.
In this report, the CPUC responds to the Executive Order by putting the costs of these programs in context with the total scale of IOU revenue requirements, describes the mechanisms by which these costs are created and shared between customers, and identifies ways that the Legislature and the CPUC can work to improve affordability.
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Conclusions in This Report: Options Exist to Save Ratepayers Money Going Forward
Inequitable rate structures and the need for unprecedented climate impact related investments have created a perfect storm driving electricity rate increases. In addition to creating financial hardship, continued rate inflation will put stress on meeting the states climate goals. Electrifying the transportation, building and industrial sectors are critical decarbonization strategies that become increasingly difficult with every increase in electricity rates.
Three areas present opportunities to control costs and reduce electricity bills: first, identifying opportunities to control the growth in utility spending. Second, identifying any opportunities for cost sharing. Third, implementing equitable rates to recover approved costs for wildfire mitigation, public purpose programs and the fixed costs of the grid.
The CPUC’s SB 695 report has identified the biggest drivers of rate increases: the growth in spending to address wildfire mitigation and the cost shift that results from legacy Net Energy Metering programs. Secondarily, energization and energy transition related investments in transmission and distribution infrastructure are also putting upward pressure on rates.
This report concludes with strategies that address these costs to save ratepayers money going forward:
1. All energy-related mandates should be assessed for overall cost-effectiveness with the goal of achieving the lowest possible rates for all customers of each utility.
2. Supplement essential wildfire mitigation programs and extreme weather-related catastrophic event response costs with other sources of funding.
3. Identify cost-reduction measures by integrating wildfire mitigation strategies into the existing General Rate Case process.
4. Equitable rate structures: Refine the elements of Net Energy Metering so that all customers share wildfire mitigation, public purpose programs and system costs.
5. Redistribute the Climate Credit to customers most impacted by increasing electricity costs.
6. Fund today’s and future cost-shifting programs from non-ratepayer sources.
7. Ensure that programs benefitting all electric customers are supported by all customers, including customers of publicly-owned utilities.
This report also describes ways in which programs add to overall costs and explains the ratepayer impact of how new programs create and distribute new costs and benefits.
Ratepayer-Funded Programs Have Delivered Benefits in
California and Across the United States
California’s pioneering investments in clean energy technology have had impacts around the world.
Customers of investor-owned utilities are funding programs and tariffs that bring many benefits:
electricity bills have been the vehicle to fund the incubation and commercialization of technologies,
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CALIFORNIA PUBLIC UTILITIES COMMISSION 5
including photovoltaic solar and battery storage, as well as the means to integrate renewable energy through programs such as time of use rates enabled by investments in advanced metering infrastructure.
Historically, California’s programs have supported every stage of technological development:
• Innovation, through programs like the Electric Program Investment Charge program (EPIC),
• Pilots, like a new program harnessing vehicle-to-grid technology to turn Oakland United School District’s newly electrified school bus fleet into a virtual power plant, and • Deployment at scale, such as competitively bid generation projects through the Renewables Portfolio Standard.
These investments continue today through innovation with next-generation smart meters, microgrid technology, smart homes, generation that is increasingly disaggregated, and mechanisms to procure new renewable generation technologies like offshore wind.
As we move through the Innovation, Pilot, and Deployment process, we need to constantly evaluate whether the programs are succeeding on their own terms and whether their benefits outweigh their costs. In addition, the CPUC needs to be constantly evaluating the opportunity costs of the decisions to fund one approach over another. This is especially true of well-established areas like energy efficiency.
For some of these investments, all utility customers are sharing the incremental cost of programs that provide higher-cost individual benefits to a select group of customers or to private industry.
Socializing investments can provide substantial benefits, such as helping certain small companies enter the renewable energy industry, providing energy efficiency or distributed energy resources to a group of low-income households, or improving plumbing and ventilation in public schools. These programs can bring important benefits and can avoid certain other costs. However, unless there is a non-utility source of funding, the costs of these investments are divided among all customers, and bill savings for one customer necessarily increases costs for everyone else.
The Nature of Electricity Necessitates Infrastructure Sized to Meet Highest Potential Demand
Unlike commodities such as water, natural gas or gasoline, electricity does not persist if it is not used or stored after it is generated.
Considerable efforts are being made to put excess grid energy to work: batteries use electricity for charging, pumped storage facilities use electricity to move water to generate electricity later, time of use rates encourage customers to shift their energy use to daytime when solar energy is plentiful, and electric vehicles and buildings are a growing source of demand.
Electricity generators are generally compensated through contractual commitments to purchase energy or tariffs, and some are further compensated for the guarantee that they will be ready to serve
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demand whenever needed. Likewise, the grid is built to efficiently share electricity generation but must also be sized to meet the highest potential demand. Accordingly, using less energy does not always result in cost savings. While guaranteed load reduction measures are increasingly valuable at times of high usage, at other times, more load can mean lower rates.
One key to future cost reduction is increased electricity consumption from buildings and transportation electrification and other new loads, combined with flexible load measures that are targeted, predictable and controllable for system needs. This can bring relief to all customers: when existing infrastructure is used more efficiently and the same fixed costs are spread across a greater volume of electricity provided, customers’ total energy costs can be reduced, and climate change action can be achieved at least cost.
Today’s Electricity Rates Trajectory
As the CPUC has detailed in its annual rates report,1 today’s rate increases are not driven by prices of contracts for new renewable energy generation.
Broadly, ratepayer bills are rising because of: wildfire risk reduction surrounding utility infrastructure, inequitable rate structures, programs that require energy procurement that is not needed or is not competitively priced, and programs that provide bill reductions or discounts to one group of ratepayers, thus leaving other customers with a larger share of overall costs.
In 2024, ratepayers of the three largest electric utilities paid a collective $54 billion in rates for the cost of utility services and investments.
2 While the CPUC looks for every opportunity to distribute costs fairly, collecting revenue through rates is inherently regressive: low-income Californians pay a higher share of their income for utility bills than higher-income Californians. 3 Distributing Costs and Benefits Fairly Is Key to Affordability The electric system is large and dynamic, and numerous programs distribute the costs and benefits of it differently – and so distributing costs and benefits fairly is essential to affordability.
In a variety of policy decisions, the CPUC seeks to distribute costs progressively and aid California families who most need help reducing their utility bills. The CPUC also seeks to measure programs using cost-effectiveness tools that are continuously vetted by stakeholders. However, rising costs 1 See the 2024 SB 695 Report or the 2024 Padilla report. 2 This includes a $12 billion proxy estimate for CCA generation costs, and subtracts the impact of the climate credit. 3 Severin Borenstein, Meredith Fowlie, and James Sallee “Paying for Electricity in California: How Residential Rate Design Impacts Equity and Electrification” (September 2022). Paying for Electricity in California.
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for the system and operations as well as requirements and programs beyond core utility services are causing electricity rates to increase significantly in recent years.
Many of these programs have benefits as well. The question presented by Executive Order N-5-24 is whether costs can be reduced and whether costs and benefits are being distributed in ways most fair to all customers, and in ways that enable California to achieve its clean energy and electrification goals.
The CPUC Has Taken Actions to Mitigate Rising Rates
As the CPUC has recognized in its annual SB 695 reports, 4 electricity rates for customers of
California’s electric IOUs have been projected to increase faster than inflation. As the economic regulator of the state’s IOUs, the CPUC limits approvals to necessary costs and identifies cost saving measures wherever they can be found.
The CPUC’s adopted monthly flat rate of $24.15 for those who can pay and $12 per month for low-income customers reflects a positive shift toward more equitable ratemaking practices and movement away from regressive cost collection. The flat rate requires all customers to pay the same amount for a portion of utility costs that do not vary with volume of usage and gives low-income households a discount. It is a more progressive method to allocate costs than per-unit charges. More CPUC actions designed to decrease bills for ratepayers as a whole with a focus on equity are described in the appendix.
The Impact of Legacy Contracts
After California legislation required its IOUs to divest generation assets, long-term clean energy contracts have been essential to meeting reliability needs while supporting emerging clean energy technologies. Such contracts, however, can also lead to long-term costs for ratepayers, particularly when they create ongoing financial commitments like contractual obligations or tariffs that extend benefits to electricity generators over time.
One example of an ongoing cost is legacy renewable energy contracts signed more than a decade ago. Load serving entities are required to procure sufficient energy to serve their customers long before it is needed, which is essential for reliability and for hedging against market volatility. Legacy contracts thus deliver benefits, and also impact ratepayers: in 2024, ratepayers paid an estimated $1.2 billion more than they would pay today for RPS contracts signed between the years 2000 and 2016.5
4 See the 2024 SB 695 Report.
5 This estimate includes all RPS contracts signed between 2000 and 2016. This includes Qualifying Facility Standard Offer, ReMAT, BioMAT, and BioRAM. BioMat and BioRAM incurred an estimated $25 million in above-market costs, and ReMAT cost ratepayers approximately $5.4 million.
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The CPUC has required utilities to renegotiate lower, market-competitive prices for these contracts when they are up for renewal, but above-market contracts persist.
These legacy contracts, together with other legacy costs, also have the unintended effect of creating a cost-savings value stream for any customer who can independently procure or self-generate electricity and thus off-set higher volumetric charges for energy, while still using the grid. In doing so, these customers avoid legacy and other fixed costs, and necessarily shift costs to other customers.
Many Investor-Owned Utility Programs are Mandated by State Laws
As stated in this report, most electricity programs could be funded through non-ratepayer funds.
This would shift costs away from customers.
The Legislature can also take statutory action to repeal or significantly revise mandated electricity programs that result in ratepayer costs that are higher than necessary for safe, reliable, clean electricity.
What is Cost Effectiveness, and How Does it Affect Rates? When a utility program has costs, rates rise, since those costs are paid on ratepayer bills. Some programs also reduce costs that are borne by ratepayers, but unless these reductions fully offset the costs, ratepayers will experience a rate increase. This section explains why.
Every Utility Program Carries Operational and/or Fixed Costs In California, as in nearly every state, Investor-Owned Utilities (IOUs) collect operational costs on a “cost of service” model: IOUs are permitted to collect all the costs of providing electricity service to customers. The IOUs’ operations are a straight pass-through of costs. Utilities do not earn a profit on these costs.
When IOUs invest in infrastructure – substations, transmission, distribution lines, metering infrastructure, and more – they earn a return on these investments, known as their “authorized rate of return,” or profit. The capital invested by the utility plus a rate of return are paid back over time by all customers.
Each year, the total amount of a utility’s operational costs and an amortized portion of capital investments is divided up among all customers of the utility and allocated for collection largely according to the amount of electricity used. An electrical bill may also include electricity generation costs charged by a non-utility load serving entity such as a Community Choice Aggregator or an Electric Service Provider.
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Together, operational and capital costs include every single utility program. Again, under the structure of the Legislature, the CPUC, and the utilities, every program that the Legislature directs the CPUC to implement via the utilities is either an operational cost, a capital cost, or both, and is paid for by ratepayers. Figure 1 summarizes the 2024 revenue requirement for the three large electric IOUs.
Figure 1. The combined 2024 electric revenue requirement for PG&E, SCE, and SDG&E, after subtracting the California Climate Credit. This estimate uses IOU generation costs as a proxy for Community Choice Aggregator generation costs. The majority of these costs must be paid to the utilities, regardless of electric sales. 2025’s revenue requirement is projected to be approximately 5- 9% higher than 2024’s.
The Capital Costs of the System Are Long-Term Investments That Support Numerous Goals
Capital costs include the physical infrastructure needed to deliver electricity to customers. Much of the recent increase in distribution and transmission costs are upgrades to improve system safety and reliability. This system must be built to meet peak system demand, and costs are not reduced if the 0 10
20 30
40 50
60 Revenue Requirement ($ Billions)
Breakout of ~$54B 2024 Electric Revenue
Requirement
Other
Public Purpose Programs
Transmission
Distribution
Generation
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CALIFORNIA PUBLIC UTILITIES COMMISSION 10
system is used less at certain times of the day on certain days of the year. Long-term investments in the system make the system stronger, more resilient and better able to facilitate electrification of end uses, but they are also sunk costs that must be repaid, and therefore limit California’s options to reduce rates.
Under the Current Cost Allocation Structure, Some Customers Pay Less Operational and Fixed Costs While the Majority of Customers Pay More
Under the current cost allocation structure, some advantaged customers pay less than their share of operational and capital costs while disadvantaged customers pay more than their share of both, especially because more advantaged customers have benefitted from the NEM subsidies paid by all other customers. This is partially caused by a policy that eliminates the connection between the revenue an electric utility collects and the amount of energy they sell.
Observers often believe that utilities are seeking to sell more electricity to customers. This is an inaccurate viewpoint. Utilities are indifferent to how much electricity they sell to customers, because of an important energy policy that California adopted in the 1990s that breaks apart electricity sales from utility budgets. Numerous states have followed California’s pathbreaking approach, and it has been foundational to the success of programs like energy efficiency and net energy metering. This “decoupled” approach means that if a utility sells more or less electricity in one year, any revenue over-collection or shortfall will either be returned to customers (in the case of over-collection) or collected (in the case of shortfall) the next year. Utilities’ revenues are not linked to the amount of electricity they sell, so they have no incentive to sell more or less electricity to any group of customers or to ratepayers as a whole.
Because most operational and capital costs are fixed in advance and allocated on an annual basis, any program that provides rate relief for one customer group results in a shift of operational and fixed costs to another. The second group gets a rate increase, while the first group gets a rate or bill decrease. Figure 2 demonstrates the shifting of such costs from participants in such a program to non-participants. Electricity costs for the customers who don’t receive the exemption can rise dramatically – an effect we are seeing today.
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Figure 2. Animation showing the impact on customers who are not participating (blue) in a program, such as NEM 1 and 2, that allows other customers (grey) to reduce their contributions to direct costs. As fewer customers contribute to direct costs, the rest of customers pay higher rates to compensate. This figure is illustrative and does not reflect exact costs of any particular program. To view the animation, open this document in the desktop version Adobe, click on the graphic and “trust” the document.
This happens for a few reasons:
• In the short term, the cost of the entire physical electric system doesn’t drop when less electricity is sold. As a result, allowing some customers to not pay for their share of fixed costs moves their share onto everyone else. Some programs may reduce costs in the long term, but only if they directly address the drivers of fixed costs. • Numerous programs mandated by the Legislature require customers to pay for expensive electricity that would not be able to compete in market-based requests for offers. When utilities, CCAs, or Energy Service Providers are required to compensate generators for expensive electricity, such as for exports from rooftop solar under the Net Energy Metering Tariff, the customers who purchase less electricity overall are purchasing less of the expensive commodity, too. And in turn, the remaining customers who cannot reduce their electricity purchases are paying for a greater share of the more expensive electricity.
In general, the customers who are purchasing less electricity are those who own their homes and can afford to buy or lease rooftop solar panels and in-home battery storage. On that basis, we know that advantaged customers are paying less fixed and operational costs while disadvantaged customers are paying more.
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Net Energy Metering
Net Energy Metering (NEM) program costs are one of the largest contributors to rising electricity rates for customers that do not have rooftop solar. According to the Public Advocates Office, the NEM program’s and the Net Billing Tariff’s (NBT) combined $8.5 billion cost shift constitutes 21- 27% of the average non-participating customer’s bill.
The NEM 1.0 and NEM 2.0 programs increase electricity bills in two ways: (1) customers pay for the generation that is exported to the grid from another customer’s NEM system at a higher rate than other available generation, and (2) customers pay for the part of bill savings experienced by NEM customers because the program allows rooftop customers to bypass their share of direct costs to maintain the electric grid, which other customers without rooftop solar end up paying (see figure 2, above).
IOU customers without rooftop solar are paying NEM customers for the generation they send to the electric grid at a rate that exceeds the cost of generation otherwise available from the grid. NEM
1.0 and NEM 2.0 customers are compensated for electricity exported to the grid at the retail volumetric rate, which exceeds the marginal cost of avoided wholesale generation purchased for that customer. IOU customers without rooftop solar pay this increased cost to NEM customers for 20 years after their grid interconnection dates.
Distributed energy resources, including batteries, electric vehicles, and heat pumps, are a part of California’s overall electricity future, and new policies are helping to send improved price signals to these resources so that they can best support electric grid needs. From April 2023 on, new rooftop solar customers—will receive compensation through the new Net Billing Tariff (NBT), which provides compensation that is more aligned with the value of the generation the systems provide to other customers. It also includes more generous subsidies for systems with battery storage compared to rooftop solar. This cost increase, however, is not fully mitigated by the new Net Billing Tariff (NBT): NEM 2 customers who switch to the NBT can create a cost shift that is 76-82% as high as their cost shift under NEM 2.
Cost Effectiveness Approaches
Cost effectiveness is a heavily contested concept. Two approaches have the most direct relevance to rates:6 the Ratepayer Impact Measure, which identifies the extent to which savings for one customer shifts costs to another, and the Total Resource Cost test, which measures financial costs and benefits to all ratepayers and the utility. Both tests measure exclusively monetary costs, and do not 6 There are two additional tests described in the CPUC’s Standard Practice Manual: the Participant Cost Test, which measures whether a program is financially beneficial to participants, and the Program Administrator Test, which measures costs and benefits to the utility or entity administering the program. The Societal Cost Test measures costs and benefits to society and was recently adopted to use on an informational basis by the CPUC in D.24-07-015.
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include non-monetary benefits and costs such as the societal cost of carbon and health or safety benefits.
Generally, when a program’s financial benefits to ratepayers outweigh its costs, it will have a Total Resource Cost effectiveness score over 1.0 and it will lower total system costs relative to other resources. Conversely, a score below 1 indicates that a program will raise total system costs relative to the alternative. A score below 1.0 on the Ratepayer Impact Measure indicates that the program raises rates by creating more costs for non-participating customer than it saves for the grid as a whole.
In the time available to prepare this report, the CPUC has not carried out a comprehensive cost effectiveness review of all programs under its purview. In many cases, the statute directing the CPUC to establish the program does not require that the program be cost effective. When the CPUC examines cost effectiveness of an electricity program, it is typically conducted within CPUC proceedings, during which dozens of stakeholders litigate the analysis and results.
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Section 1 - Response to Executive Order
Request to Review Programs
Figure 3 shows the contribution to rates of programs funded through electric IOU revenues. Note that this figure conflates the cost shifting (indicated by textured wedges) visualized in Figure 2 with direct costs like the expense of purchasing energy from biomass incinerators in the BioMAT and NEM 1, 2, and NBT
(Not C-E)
ESA (Not C-E)
Programs without C-E
Scores
CARE/FERA (No Score)
Demand Response
Energy Efficiency
Wildfire Mitigation
All Remaining
Revenue Requirement
(Transmission,
Distribution,
Generation, O&M, etc)
Above-Market Costs of
Legacy IOU RPS Contracts
Uncollectibles
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BioRAM programs. The chart is best understood to show the potential impacts on IOU electric revenue collections (and therefore system average rates) if programs were funded outside of electric rates. Eliminating programs whose primary rate impact is through cost shifting would affect which customers pay certain costs, but would have virtually no direct impact on average bills. For example, repealing and eliminating California Alternate Rates for Energy (CARE) would dramatically increase costs for the most vulnerable ratepayers and lower costs for wealthier ratepayers, commercial customers, and industrial customers. 7 It would not impact average bills
because savings for one group translate directly into costs for another.
Because each customer class (residential, commercial, industrial) contributes different amounts to each program and cost shift, class-specific impacts would vary from the amount shown in the pie chart. For example, Net Energy Metering and the Net Billing Tariff primarily shift costs within the residential class: funding the cost shift from an outside source would create significantly greater than
15.6% savings for non-participating residential customers.
A full list of programs with their approximate annual costs can be found in the Appendix.
What All of This Means: Opportunities to Cut Rates Today and For the Future
There are opportunities to cut rates today, which will promote affordability. Finding ways to save ratepayers money is essential. The CPUC’s analysis shows the following:
1. For context, in 2024 electric ratepayers will pay approximately $54 billion in rates to the three large IOUs and to community choice aggregators. In 2025, revenue requirements are projected to increase an estimated 5-9%.
8 2. From 2019 to 2024, the IOUs collected approximately $24 billion in wildfire mitigation and insurance premium costs.9
3. While the vast majority of industrial, commercial, and residential customers do not have solar panels, the California Public Advocates Office estimates that they will pay approximately $8.5 billion in 2024 for the 15% of customers who do, under the NEM 1, 7 Approximately three quarters of the CARE subsidy is paid for by non-residential customers. If there were no CARE program, average rates within the residential class would rise: CARE customers would pay approximately $1.9 billion more, while non-CARE residential customers would only save approximately $500 million. 8 This estimate uses IOU generation costs as a proxy for CCA generation costs, and subtracts the impact of the California Climate Credit. The overall increase in revenue requirement depends on the result of pending proceedings. 9 Approximately $18 billion was placed into revenue requirements through 2023. See 2024 SB 695 Report, p. 53. At the time of this report’s drafting, 2024 costs were estimated to be approximately $6 Billion.
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NEM 2, and NBT tariff programs. The Public Advocates office estimates that this cost shift represents 21-27% of residential bills.10
4. The flagship low-income discount programs, California Alternate Rates for Energy (CARE) and Family Electric Rates for Energy (FERA) shift approximately $1.75 Billion to non-participating customers. Nearly three quarters of these costs are paid by non-residential customers.
5. The remaining electricity programs that the CPUC orders the IOUs to carry out based on mandates from the Legislature total approximately $2 to $2.5 billion per year. Half of this amount is spent on programs demonstrated to be cost-effective. The remaining half is spent on programs that have benefits and costs, but have not been reviewed for cost-effectiveness.
Based on the above facts, the following are potential principles for consideration. These require statutory changes, budget from another source, or other methods of implementation:
1. Fund the NEM and NBT Cost Shift From Non-Ratepayer Sources: Achieve a rate drop in 2025 of approximately 15.6% systemwide11 by funding $8.5 billion for NEM 1, NEM 2, and NBT customers from non-ratepayer sources. Sustain the rate drop through a commitment to steadily increase the allocation as the number of NBT customers, and the associated cost shift, grows.12
2. Reduce the NEM and NBT Cost Shift: the cost shift created by NEM 1, 2, and the NBT could be reduced by:
a. Shorten legacy periods: almost all NEM 1 and 2 customers have more than 10 years before they will be defaulted onto the NBT. Nearly half have 15 or more years of this legacy period remaining. By reducing the legacy period from 20 years, NEM 1 and 2 customers could be defaulted onto the Net Billing Tariff sooner. This would save non-participants billions of dollars.
b. Tie compensation for excess generation from solar systems to rates in effect when NEM customers interconnected: Because NEM customers receive retail rates for any excess electricity that passes through their meter, the amount paid by non-NEM customers for this excess energy is increasing over time as rates rise.
Tying compensation for excess generation to the rates in effect when a NEM or NBT customer signed up for the tariff would mitigate the increase in cost shifts. c. Establish a Grid Benefits Charge for NEM and NBT customers: Solar customers use the grid to import and export energy, but a large portion of their 10 Per the Public Advocates Office. 240822 Public Advocates Office 2024 NEM Cost Shift Fact Sheet. 11 Per the Public Advocates Office, the NEM 1, 2, and NBT cost shift totals $8.5 billion in 2024. 240822 Public Advocates Office 2024 NEM Cost Shift Fact Sheet.
12 While the NBT is an improvement over NEM 1 and 2, it does not eliminate the cost shift. NEM 1 and 2 customers have a 20-year legacy period, and the majority connected within the last 5 years. If volumetric electric rates continue to increase, the cost shift from these customers will continue to grow.
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existing share of system costs is necessarily moved to other customers’ bills when their systems are installed. A monthly charge for NEM and NBT customers would help to reduce the amount that shifts from NEM customer bills to non-NEM customer bills.
d. Tying legacy periods to the customer, not the system: currently, the 20-year legacy period before which NEM 1 and 2 customers are defaulted onto the NBT is linked to the installed system, not the customer. Systems could be converted to the NBT when the home changes ownership or at the end of the legacy period, whichever is sooner, rather than only when the system reaches the end of its legacy period.
3. Use Stable Non-Ratepayer Funds to Increase the CARE and FERA Discount:
Because fixed costs are high and will remain so for the foreseeable future, a stable source of non-ratepayer funding can be used for a larger direct subsidy to low-income Californians on their electricity bills.
4. Fund Other Programs From a Non-Ratepayer Source: Achieve a rate drop of up to approximately 2.3% starting in 2027 through statutory changes in 2025 that fund programs without cost-effectiveness scores from non-ratepayer sources. These programs also provide benefits - repealing them entirely would produce ongoing savings significantly lower than
2.3%, by also eliminating any benefits they provide.
5. Fund Any Future Cost-Shifting Programs from Non-Ratepayer Sources: Future programs that give exemptions to certain customer groups should be allocated funding from non-ratepayer sources so that other customer groups do not pay for them.
6. Use Existing Review Processes of Utility Spending: The existing General Rate Case (GRC) process is often the best way to ensure that all costs are reasonable and cost-effective, particularly in wildfire-related areas. New programmatic mandates should be evaluated through the GRC instead of standalone applications, such as those to collect costs tracked in memorandum accounts.
7. If a Program Benefits all Electric Customers, All Electric Customers Should Contribute: Any program funded by electric ratepayers for the benefit of all of California should be paid for by all electric customers, including the customers of publicly owned utilities.
8. Prioritize the Needs of Ratepayers: All energy-related mandates should be assessed for overall cost-effectiveness with the goal of achieving lowest possible rates for all customers of each utility. In addition, statutes ordering the CPUC to prioritize a specific industry’s needs, the needs of a specific customer group, or other needs beyond the delivery of safe, reliable and clean energy13 over the needs of all ratepayers are likely to increase costs. 13 For example, SB 1090 requires ratepayers to reimburse $85 million in lost local government tax revenue due to the closure of Diablo Canyon Nuclear Plant and pay $128 million in employee retention funding beyond what the CPUC approved. These priorities contribute to increases in PG&E customer bills.
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Actions to Be Taken Under the CPUC’s Authority
The following are examples of actions the CPUC could take to reduce ratepayer costs:
1. Open an Energy Efficiency Rulemaking: The CPUC plans to open a new rulemaking on energy efficiency in 2025. It will include a focus on cost effectiveness.
2. Move toward incorporating a greater share of ratepayer costs into General Rate Cases for holistic review and decision-making.
3. Evaluate new programs for cost-effectiveness where appropriate. Identify statutory barriers to implementing cost effectiveness tests on mandated programs.
4. Improve risk-informed spending by continuing efforts in the Risk-Based Decisionmaking Framework proceeding, directing the utilities to provide better and more consistent information about how they incorporate risk into their GRC funding requests.
5. Consider reprioritizing transportation electrification spending by focusing on critical grid investments and pausing $1 billion in new ratepayer charges previously authorized in the Transportation Electrification Framework decision.
6. Approve lower-cost wildfire risk mitigation methods where appropriate.
7. Identify programs meeting the following criteria:
a. Programs that require ratepayers to purchase energy from specific generation types that are not competitive with alternative RPS-eligible resources.14 Removal of costs from rates may require legislative action.
b. Programs that are underutilitized and could return funds to ratepayers.
8. Continually improve the efficiency of the CPUC’s administrative processes. 14 Above-market mandated procurement can occur through tariffs or non-competitively bid contracts.
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Section 2 – Response to Executive
Order Request to Consider Ways
to Improve the Effectiveness of
the California Climate Credit
The California Climate Credit is a twice-per-year bill credit automatically provided to all residential and certain qualifying small businesses. Qualifying energy intensive trade-exposed (“EITE”) industrial customers also receive the California Industry Assistance credit. The funds originate from the California Cap-and-Trade Program, which requires power plants, fuel providers, and large industrial facilities that emit greenhouse gases to turn in for compliance carbon pollution allowances equal to their greenhouse gas emissions.
The credit is designed to help utility customers during the transition to a low-carbon future by sharing proceeds from the sale of allowances with customers. In 2025, the residential climate credit will total $1.39 billion (an average of $120 per customer), with another $117 million for small businesses and $104 million for EITE industrial customers.
As noted in this report, the burden of high rates does not affect all customers evenly. Pursuant to Executive Order N-5-24, this section explores several potential approaches to maximize the effectiveness of these funds.
The minimal administrative cost is a particular strength of the identified approaches.
Allocating the Climate Credit to Specific Customer Groups Currently, every residential customer receives a credit on their bill twice per year as their share of the proceeds from California’s cap and trade program. In 2025, more than 11.6 million customer accounts will receive an average of $120.
The Climate Credit presents a significant equity opportunity for California. The Climate Credit could be reallocated to customers who need it the most: first, to all customers who receive the CARE benefit, and second, all customers without rooftop solar who are paying for those who have it.
The potential bill credits under three possible alternative approaches are outlined in the table below:
allocating the climate credit exclusively to CARE customer accounts, and allocating it to all non-Page 48 of 84 CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
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NEM 1.0, 2.0, and Net Billing Tariff accounts, and allocating it to non-NEM/NBT CARE and FERA customers, along with non-NEM/NBT customers in the hottest climate zones.
Additionally, funding from other sources could be added to the climate credit, increasing the customer benefits shown below.
Allocation
Total Residential
Climate Credit,
2025
Estimated Total
Benefiting
Accounts
Resulting Bill
Credit
All Customer
Accounts (status
quo)
$1.39 Billion 11.6 million $120
CARE and FERA
Customer
Accounts only
$1.39 Billion 3.1 million $454
Non-NEM 1.0,
2.0, or NBT
Customer
Accounts
$1.39 Billion 9.9 million $142
Non-NEM/NBT
CARE, FERA,
and Customers in
Hottest Climate
Zones
$44515
15 “Reallocating the Residential California Climate Credit to Low-Income Customers.” Dollar value may not be directly comparable to others in this table because the workpaper may have used different assumptions.
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Volumetric Distribution of Climate Credit
Currently, the Climate Credit is given twice per year in a lump sum. It could be allocated on the basis of usage, reducing the volumetric rate for electricity. While this would not reduce total annual bills, it could potentially make electrification more appealing to ratepayers. It would also reduce month-to-month bill volatility, easing ups and downs of utility bills for many Californians. Any change from a non-volumetric to volumetric return of the climate credit must be reflected in the Cap-and-Trade Regulation.
Rate Reduction if $1.4B
Residential Credit were Allocated
Volumetrically
$0.023/kWh
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Section 3 - Response to Executive
Order Request to Recommend
Ways to Reduce Wildfire
Mitigation Costs
This section is the joint response of the Office of Energy Infrastructure Safety and the CPUC in accordance with Paragraph 5 of Executive Oder N-5-24.
Background
Wildfire represents the single most significant financial and safety risk for California’s investor-owned electrical utilities. California is experiencing compounding impacts of climate change, as wildfires become larger, more intense, and harder to contain than ever before. Because wildfire represents such a considerable risk, utilities are required to prepare Wildfire Mitigation Plans (WMPs) describing their strategies for reducing wildfire risk for review and approval by the Office of Energy Infrastructure Safety (Energy Safety). As noted above, between 2019 and 2024, IOUs collected approximately $24 billion from ratepayers to pay for wildfire mitigation costs and insurance premiums.
16 The WMPs have dramatically improved the way electrical utilities in California understand and reduce the risk of utility-caused wildfire. However, the cost of implementing these plans has resulted in associated wildfire mitigation-related rate pressures.
Wildfire Risk Mitigation Will Continue to Contribute to Electricity Rate Increases
Ignition risk associated with electric lines can be reduced through a variety of approaches including vegetation management, grid hardening, replacing uninsulated lines with covered conductors, and undergrounding.
• Undergrounding: moving above-ground lines beneath the surface. 16 Approximately $18 billion was collected through 2023. See 2024 SB 695 Report, p. 53. At the time of this report’s drafting, 2024 costs were estimated to be approximately $6 Billion.
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• Covered Conductor: replacing wires with heavily insulated alternatives that are far less likely to spark than traditional wires.
• Other Grid Hardening and Grid Design: can include replacing wooden poles with fire-resistant materials, replacement or strengthening of infrastructure, segmentation of lines to allow isolation of faults, or adding sensors to cut power when electric faults are detected. • Vegetation Management: Removing and trimming trees and other vegetation around electrical lines and equipment to reduce the risk of vegetation coming into contact with power lines and reducing the amount of dry vegetation close to electrical equipment.
While each approach reduces wildfire risk to varying degrees, undergrounding raises rates the most and takes the longest to implement. Although undergrounding costs are hard to estimate and vary dramatically because of many factors, including topography, estimates show that undergrounding every IOU distribution line in high fire threat areas could cost an estimated $92-224 billion.
Undergrounding transmission would be significantly more costly. In contrast, installing covered conductor would cost approximately one-fourth as much.
17 Of the four approaches, undergrounding is in certain locations the most effective option, and is therefore an essential tool in utility efforts to reduce wildfire risk. SB 884 facilitates longer-term utility infrastructure undergrounding investments, but does not provide a source of funding for this work other than increases in customer bills.
No matter the approach, the costs associated with hardening the electric grid to reduce the risk of utility-ignited wildfires are borne by ratepayers through increases in electricity rates. The most effective way to reduce the electricity bill impact is to fund these investments from a source other than ratepayers.
Consolidating and Streamlining Utility Funding Requests Will Provide Some Relief
These rate pressures may be reduced through increased transparency and improved coordination of cost approval processes, electric underground infrastructure construction, and fuel treatment efforts.
Currently, electrical utilities request wildfire mitigation funding through multiple mechanisms at the CPUC, including GRCs, memorandum accounts for the recovery of WMP costs, and, prospectively, additional applications for large electrical undergrounding plans. The multiple streams of funding for 17 Depending on the IOU, undergrounding distribution lines costs $2.3-$5.6 million per mile, while transmission undergrounding is significantly more expensive: the Tehachapi Renewable Transmission Project cost $139 million (in 2025 dollars) per mile to underground. Covered conductor costs $770,000 - $1.35 million per mile. There are approximately 40,000 miles of above-ground IOU distribution lines in California’s High Fire Threat Districts. Per-mile costs are drawn from recent IOU filings and CPUC decisions. This calculation is highly uncertain.
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wildfire mitigation decrease transparency, complicate oversight, and reduce accountability, leading to increased rates.
The CPUC’s GRC process is the most transparent available process and requires the highest levels of cost justification. The GRC allows parties to the proceeding to scrutinize proposed spending forecasts and present evidence in support of lower or higher amounts than those proposed by the electrical utilities. Based on the evidence presented, the CPUC ultimately prospectively approves a fixed amount of funding utilities may recover from ratepayers each year of the four-year GRC cycle.
In the case of costs required to implement WMPs, the CPUC is required to allow the utilities to track and record additional costs, above approved GRC forecasts, and seek cost recovery from ratepayers for these expenditures.
Solutions Requiring Legislation
Integrating Wildfire Mitigation Plans into Utility General Rate Cases
The implementation measures included in Wildfire Mitigation Plans (WMPs) are not currently subject to the coordinated cost review and evaluation that other utility programs and investments receive. This may unnecessarily drive costs up and decrease transparency of wildfire-related spending. Applications to recover many of these costs are often filed after the work is completed and involve lengthy, contentious proceedings to evaluate potential overlap with GRC approvals and after-the-fact reasonableness of expenditures. The time delay increases debt carrying costs that must be paid by ratepayers.
The Public Utilities Code could be amended to require utilities to integrate WMP costs into the normal planning and budgeting process (their GRC) instead of treating it as a stand-alone activity.
While the CPUC could still authorize utilities to track and recover WMP implementation costs that exceed GRC-authorized amounts, utilities would need to include their entire forecasted amounts in GRC applications. This modification would reduce ratepayer costs by allowing CPUC review of planned expenditures before work is completed and help ensure that utilities choose the most cost-effective mitigations.
The aim of the alignment would be to increase administrative efficiency by reducing the rate at which utilities prepare comprehensive wildfire mitigation plans from once every three years to once every four years. While the WMP process to date has successfully driven electrical utilities to rapidly improve how they understand and address wildfire risk, utilities have matured to the point where they can be expected to incorporate their wildfire mitigation planning into the GRC process.
Synchronizing WMP planning with planning for other spending, along with additional procedural changes, would improve clarity and reduce redundancy in the Energy Safety and CPUC review processes. The elimination of more than a dozen CPUC resolutions ratifying WMPs every year
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would lead to significant reductions in planning, preparation, review, and litigation expenses for the CPUC, Energy Safety, and utilities.
Finally, this proposal would improve utilities’ certainty as to what wildfire mitigation activities must be completed as well as the associated approved budgets thereby avoiding complex factual determinations around the reasonableness of utility incremental spending over GRC approvals.
These changes would largely mirror those proposed in SB 1003 (Dodd, as amended August 28) during the 2023-2024 legislative session. Energy Safety would continue to review and approve or deny WMPs while the revenue approval remains with the CPUC.
This alignment would build on lessons learned from the past five years and prepare California for the next phase of utility wildfire risk reduction. It would also preserve successful features of the current oversight model:
o The reforms keep the focus on mitigating utility wildfire risk. Energy Safety will continue to set requirements and evaluate the quality of WMPs.
o Every year, Energy Safety would assess utility implementation of WMPs and provide feedback to utilities and CPUC.
o Every year, utilities would continue to apply for certification from Energy Safety based on enumerated statutory criteria rooted in proactive investments in safety. By meeting these criteria, the utilities demonstrate their commitment to safety culture, safety based executive compensation, transparent reporting, and continued maturity in their planning efforts. In return, they can be entitled to a presumption of reasonable action in a proceeding before the CPUC to recover costs in the event of a utility related wildfire. o The CPUC would evaluate and approve wildfire spending costs with attention to cost effectiveness.
o The CPUC would still have authority penalize utilities who do not implement their WMPs.
Reducing the Construction Costs of Burying Electric Utilities When undergrounding their facilities, electrical utilities do not consistently receive information on the location of other utilities’ underground infrastructure until two days before excavation begins. Therefore, contractors installing electric infrastructure are often required to make costly changes during construction to account for previously unknown existing underground facilities, driving up the cost of constructing new underground facilities.
These challenges could be addressed by legislation authorizing Energy Safety’s Underground Safety Board to determine how utilities must provide buried facility records to electrical and other utilities during the project planning and design phases. This would be accomplished through processes used by existing 811 underground service alert notification centers. Energy Safety’s Underground Safety
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Board would need the authority to develop regulations requiring contractors who submit a significant number of 811 tickets to provide advance notice to utility operators in the affected area.
This advance notice, which could be integrated into the 811 design process, would enable utility operators to more effectively plan for large-scale projects. This process could also be used to facilitate early Tribal notification of pending excavation activities.
Solutions Actionable on Existing Authority
Energy Safety: Better Fuels Treatment Coordination Between Electrical Utilities and Large Landowners
Electrical utilities generally plan wildfire mitigation activities independently of the extensive coordinated wildfire mitigation work occurring throughout the state. WMP initiatives activities can be costly to plan and implement as stand-alone small-scale projects and are often too limited in scale to protect electric companies' assets from wildland fires. Energy Safety could leverage its existing participation in various wildfire mitigation boards and task forces, along with its relationships with the electrical utilities, to facilitate broader coordination and integrated wildfire mitigation projects between public and private partners.
Coordination of fuel management treatment design, permitting, and environmental review work produces savings for land managers and electrical utilities. Stewardship agreements could allow multiple entities to hire a single contractor to conduct the forest fuel reduction treatments across a broader geographical area.
As an example, the 6,400-acre Liberty Utilities Resilience Corridors Project—coordinated with the U. S. Forest Service— enabled fuel reduction treatment along utility corridors and allowed the Forest Service and Liberty Utilities to share in the costs. Energy Safety can work with existing partners such as the Office of the State Fire Marshal and the California and the Wildfire and Forest Resilience Task Force to identify and facilitate similar projects.
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Section 4 – Response to Executive
Order Request to Pursue Federal
Funding Opportunities
In April 2024, the Commission adopted Resolution E-5254. The Resolution formalized support for IOU pursuit of federal funding opportunities, allowed for the establishment of a memorandum account to track spending on applications and other federal funding costs, and established a process for utilities to seek cost recovery for any required ratepayer cost shares for successful grant applications. Utilities are directed to apply for cost recovery through the existing general rate case (GRC) or application process to ensure that all projects face a sufficient level of scrutiny and opportunity for public engagement.
The utilities have also received multiple letters from CPUC President Alice Reynolds directing them to pursue all available funding opportunities, highlighting upcoming deadlines, and ordering the IOUs to report on their efforts to apply for funding.
These efforts have led to significant successes, including a $15 billion low-interest loan from the Department of Energy. Additional funding is summarized in table A-3 of this report’s appendix.
The CPUC will continue to strongly support and encourage the IOUs to secure any and all available non-ratepayer funding.
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Appendix
18 See D.23-01-005 issued in PG&E’s 2023 General Rate Case (A.21-06-021) and D.23-05-013 issued in SCE’s 2021 General Rate Case (A.19-08-013). 19 AB 1054 excludes the first $5 billion of the large IOUs’ Wildfire Mitigation Plan (WMP) capital spending from earning a return on equity. (AB 1054, Section 18). This limits rate increases directly by eliminating the investor return portion of the return on rate base of $5 billion in WMP capital spending. See Chapter IV, Wildfire-Related Costs section for each IOU’s total equity rate base exclusion amount.
20 See Chapter IV, Wildfire-Related Costs section for specific Financing Order Application and Decision numbers. 21 Under PG&E's bankruptcy plan and SB 901, the CPUC also authorized $7.5 billion in securitization (SB 901, Section 32).
22 See D.22-12-056 in proceeding R. 20-08-020.
CPUC Actions Taken to Reduce Costs
Wildfire Self-Insurance Produces Ratepayer Savings
• Cost of commercial market wildfire insurance has escalated in recent years. • The CPUC approved proposals for PG&E and SCE to implement wildfire self-insurance, estimated to have resulted in a $467 million ratepayer savings impact in 2023.18 Similar savings are anticipated for future years.
Equity Rate Base Exclusion and Optional Securitization Limit Rate Increases • As directed by AB 1054, the annual revenue requirements approved by the CPUC preclude the IOUs from recovering a Return on Equity on $5 billion in wildfire mitigation capital costs. 19 • These equity rate base exclusions are forecasted to save ratepayers as much as $2 billion over the lifetime of the assets.
• AB 1054 also allows for securitization of wildfire mitigation capital spending. Securitization benefits ratepayers by allowing the securitized bonds to obtain a lower interest rate than would otherwise be available to finance WMP capital expenditures.20 As of July 2024, the CPUC has authorized $10.9 billion in securitization bonds under AB 1054 and SB 901.21
Net Billing Tariff (NBT) Limits Cost Increases
• The CPUC reduced electricity bills for IOU customers by reducing the amount customers pay to other IOU customers who install solar or solar-plus-storage systems in the future.22 • While Net Energy Metering (NEM) 1.0 and 2.0 programs decrease electricity bills for customers participating in the programs, they increase electricity bills for all other customers. The NBT decision does not change the ongoing increased costs that non-participating customers pay for participants to remain on the NEM 1.0 and NEM 2.0 tariffs. It also does not eliminate future
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23 Comparing a NEM 2 solar-only customer to an NBT solar and storage customer. 24 See D.23-11-068 in proceeding R.20-08-020.
25 The TPR Process was established in Resolution E-5252. cost shifts: the NBT reduces the per-customer cost shift by an estimated 18-24% relative to NEM 2.23
Virtual Net Billing Tariff (VNBT) and NBT Aggregation Subtariff Limit Cost Increases • The CPUC reduced electricity bills for IOU customers by reducing the amount customers pay to other IOU customers who install solar or solar-plus-storage systems using the VNBT and NBT Aggregation programs compared to previous Virtual Net Energy Metering (VNEM) and Net Energy Metering Aggregation (NEMA) programs.24
• While VNEM and NEMA programs decrease electricity bills for customers participating in the programs, they increase electricity bills for all other customers. The decision does not change the ongoing cost shift created by customers remaining on the NEM 1.0 and NEM 2.0 tariffs. It also does not eliminate future bill increases that occur when other customers install rooftop solar and solar-plus-storage systems using the new tariffs.
Self-Generation Incentive Program Transitioned to Non-Ratepayer Funding Source • Pursuant to AB 209, the CPUC allocated $280 million from the Greenhouse Gas Reduction Fund to the Self-Generation Incentive Program (SGIP) Residential Solar and Storage Equity budget.
• This allowed the program to continue to support resiliency in low-income and environmental and social justice communities without drawing on ratepayer funds.
Intervention In Federal Transmission Owner Rate Cases Saves Ratepayers Money • The CPUC continuously advocates in Transmission Owner rate cases at FERC on behalf of ratepayers.
• Ratepayer savings are ongoing and estimated to be $5 billion since 2018, or $700 million per year.
Transmission Project Review (TPR) Process Increases Transparency of Costs • CPUC designed the TPR Process to provide cost transparency of IOUs' transmission projects before Federal Energy Regulatory Commission whose costs exceed $1 million.25 • While not always quantifiable, savings from previous FERC-derived processes between 2020 and 2023 resulted in quantified long-term savings to ratepayers of between $500 million and $1 billion. • As the TPR Process is more robust than those earlier processes, the affordability benefits to ratepayers are expected to be at least as great.
Implementation of FERC Order Saves Ratepayers Money
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 30
26 See D.23-06-008 in proceeding R.17-05-010.
• AB 209 reaffirms and clarifies that IOU participation in the CAISO is ordered by the CPUC and not voluntary. This clarification confirms that the IOUs cannot collect additional costs from ratepayers as an incentive to participate in an ISO.
• The Federal Energy Regulatory Commission (FERC) ruled in December 2023 that AB 209 is clear that incentives are not appropriate if an action is already mandatory. This adder will not be allowed in future rate cases and has an estimated cost savings of $86 million in 2024. •
The GRC Process is Transparent and Publicly Vetted
• The CPUC’s GRC proceedings require a transparent process for analyzing proposed utility costs and high levels of cost justification.
• In GRC proceedings, the CPUC requires evidence of forecasted costs and uses procedures for parties to litigate these forecasts in a public proceeding. This process enables the commission to identify necessary and cost-effective expenditures and typically leads to approvals that are lower than utility cost recovery requests.
Revision of Electric Rule 20 Prevents Ratepayers From Funding Inequitable Investments • The Rule 20A program subsidized the undergrounding of power lines for aesthetic purposes in localized areas and benefits few ratepayers at the expense of the many ratepayers. • The CPUC discontinued and is phasing down the Rule 20A Program by 2033 to prevent ratepayers from funding inactive and inequitable infrastructure investments.26 • The action is estimated to save $74 million annually through 2033.
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 31
Table A-2. Program list.
Bill or
Statute
Mandating
Program, if
Any
Ratepayer
Funding ($
Millions, unless
otherwise
noted)
%
Reduction
in Average
Rates if
Funded by
Non-Ratepayer
Funds
One-Time
Savings if
Discontinued
Cost Effective?
Blank Cells
Mean No
Evaluation Has
Been Conducted
NEM 1 and 2
PU Code
Sections 2827
and 2827.1
$8.25 Billion in
Cost Shifts21 15.2% No
CARE and FERA PU Code
Section 739.1
$1.75 Billion
(1/3rd from
residential
customers)
3.2%
Energy Efficiency
PU Code
454.55,
454.56
$810 1.5%
Yes, with non-cost-effective
components
Demand
Response
PU Code
Sections
454.5(b)(9)(C)
(i), 380,
400(c), 769
$486 0.9%
Yes, with pilots
excluded from
cost-effectiveness
requirements
Uncollectibles/Arr
earage
Management
Program (AMP)
$483 million in
2025, $204
million from
AMP
0.9%
CalSHAPE (AB
841)
PU Code
Sections
1610-1618,
1620-1627,
1630-1633
$331 0.60%
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 32
Net Billing Tariff
PU Code
Sections 2827
and 2827.1
$250 million in
cost shifts27 0.4% No
Energy Savings
Assistance (ESA)
PU Code
Section 382
~$140-200
million 0.3% No
Transportation
Electrification
Rebate Program
$200 0.40%
EPIC $185 0.3%
BioMAT/BioRA
M
PU Code
Section
399.20
$150 0.3%
SOMAH PU Code
Section 2870) $100 0.2% $517
VNEM
Approximately
$26 million in
202228
0.04% No
RES-BCT PU Code
Section 2830
~$30-50
million in cost
shifting
0.05%
DAC-GT/CSGT
PU Code
Section
2827.1
$24 0.04%
SB 1090 – Diablo
Canyon
Settlement
Agreement
PU Code
712.7
$9.48 million
in 2024, $213
million total,
27 Per the Public Advocates Office. 240822 Public Advocates Office 2024 NEM Cost Shift Fact Sheet. 28 Decision 23-11-068, page 22.
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 33
Microgrid
Incentive Program
PU Code
8370, 8371
Low millions
in 2024, up to
$200 million
over 3-6 years
RISE $0 in 2024, $50
million total $50
AB 841
(Transportation
Electrification)
PU Code
Sections
740.12,
740.18,
740.19, and
740.20.
Unknown –
shifts costs to
non-participating
customers
Fuel Cell Net
Energy Metering
(NEM-FC)
PU Code
Section
2827.10
Low millions
in cost shifting
from 120 MW
of capacity –
NEM 2
Lookback
Study found
small cost shift
from
commercial
customers
NEM-A PU Code
2827, 2827.1
Low millions
in cost shifting
Solar Equipment
List
PU Code
Section 2851 $1.28 0.01%
Clean Energy
Financing $0 0% $270.5
SGIP PU Code
379.6
$0
Unquantified
cost shifting
Unquanti
fied ~$129 million
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 34
TECH
PU Code
sections 922,
748.6
$0 0%
Community
Renewable Energy
Program (CREP)
PU Code
sections 769.3
and 913.15
$0 0%
AB 2109 –
Industrial
Surcharge
Exemption
PU Code
Sections 371
and 451.7
Unknown –
Shifts costs to
non-participating
customers
Unknown
Table A-3. Summary of federal funding secured by IOUs.
Applicant Project Award Amount Description
PG&E, SCE, CEC,
CPUC, CAISO, UC
Berkeley
CHARGE-2T
(California Harnessing A
dvanced Reliable Grid E
nhancing Technologies
for Transmission)
Press Release
DOE Factsheet
$600M Federal Share /
$901M Ratepayer Share
Reconductor 100+ miles
of transmission lines to
increase transmission
capacity to support
renewables integration.
Also supports
interconnection reform.
PG&E, Redwood
Coast Energy
Authority, Schatz
Energy Research
Center at Cal Poly
Humboldt
Tribal Energy Resilience
and Sovereignty
(TERAS) Project
DOE Fact Sheet
$88M Federal / $89M
Ratepayer
Implement nested
microgrids serving
Hoopa Valley, Yurok,
Karuk, and Blue Lake
Rancheria tribal lands to
drastically reduce outage
times.
Liberty Utilities Project Leapfrog
DOE Factsheet
$13M Federal Share /
$13M Ratepayer Share
Upgrade the distribution
system for real-time
information gathering,
greater manipulability,
CPUC RESPONSE TO EXECUTIVE ORDER N- 5 - 24
CALIFORNIA PUBLIC UTILITIES COMMISSION 35
and faster outage
management
CPUC, CEC, CA
Infrastructure and
Economic
Development Bank,
CA Labor & Workforce
Development Agency
Solar for All
EPA Solar for All
website
$249.8M Deliver residential solar
for low-income and
disadvantaged
communities across the
state.
PG&E Maintaining &
Enhancing
Hydroelectricity Section
247
DOE Award List
$34.5M for 39 different
projects
Maintain and improve
existing hydropower
facilities.
PG&E Project Polaris
DOE Press Release
$15 billion loan Expand hydropower
generation and battery
storage, upgrade
transmission capacity
through reconductoring
and grid enhancing
technologies, and enable
virtual power plants
595978301 - 1 -
COM/ARD/vhj 2/3/2026
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Order Instituting Rulemaking to
Improve the California Climate
Credit.
Rulemaking 25-07-013
ASSIGNED COMMISSIONER’S SCOPING MEMO AND RULING
This scoping memo and ruling sets forth the issues, need for hearing, schedule, category, and other matters necessary to scope this proceeding pursuant to Public Utilities Code (Pub. Util. Code) Section 1701.1 and Article 7 of the Commission’s Rules of Practice and Procedure (Rules).
This ruling also directs the utilities and authorizes other parties to file comments responding to the questions in Section 4.2 of this ruling.
1. Background
On July 24, 2025, the Commission approved the Order Instituting Rulemaking (OIR) to Improve the California Climate Credit, opening the instant rulemaking. As described in the OIR, this proceeding was initiated to consider ways to improve the effectiveness of the Climate Credit in supporting affordability.
The Climate Credit is a credit that appears on the investor-owned electric and gas utilities’ (the Utilities) customer bills. Credits are currently delivered twice a year to electric customers and once a year to gas customers. Both the electric and natural gas Climate Credits are currently delivered during traditionally low-bill months: in the spring and fall for electric customers, and once a year in the spring for gas customers.
FILED
02/03/26
03:19 PM
R2507013
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The Climate Credit comes from revenues from the State’s greenhouse gas (GHG) emissions program, renamed Cap-and-Invest under Assembly Bill (AB) 1207 (Irwin), Statutes 2025, Chapter 117 (AB 1207).
1 Under this program, covered
entities must obtain and surrender to the California Air Resources Board (CARB) allowances or offsets (together, compliance instruments) for covered GHG emissions.
Each compliance instrument represents a metric ton of carbon dioxide equivalent emissions. In-state electricity generators that emit over 25,000 metric tons annually and electricity importers face a compliance obligation for the GHG emissions associated with the electricity they generate in or import to California.
Electricity generators and importers generally pass the costs of compliance with the Cap-and-Invest Program to the electric utilities that supply electricity to end-users, who then pass those costs on to ratepayers. Natural gas utilities face a compliance obligation for GHG emissions from the combustion of the natural gas supplied to their customers, less any natural gas delivered to facilities that are covered by the Cap-and-Invest Program. Natural gas utilities also pass the costs of compliance on to their customers.
Covered entities including the Utilities may purchase allowances through CARB’s Cap-and-Invest Program quarterly auctions or purchase compliance instruments from other Cap-and-Invest Program Participants.
To protect ratepayers from Cap-and-Invest Program compliance costs, CARB allocates free allowances the Utilities on behalf of their ratepayers. The investor-owned electric utilities are annually required to consign all allocated allowances to auction. The investor-owned natural gas utilities are required to 1 From its original inception, the program was titled Cap-and-Trade; we use the term Cap and Invest here, consistent with the change to the program name in AB 1207.
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consign a minimum percentage of their allocated allowances to auction each year.2 The Climate Credit stems from the revenues from consigning freely allocated allowances at auction. It is on these and related issues we focus in this proceeding; we do not consider issues related to the Utilities’ compliance activities, or issues related to Cap-and-Invest compliance costs.
Authority and direction applicable to the Utilities’ revenues from the consignment of their directly-allocated allowances comes from three main sources: CARB’s regulations, Public Utilities Code Section (Pub. Util. Code Section) 748.5, and numerous Commission decisions. Various legislation has also provided guidance.
Until the 2025 revisions in AB 1207 – which are detailed further below – Pub. Util. Code Section 748.5(a) required electric utilities’ revenues to be returned directly to residential, small business, and emissions-intensive, trade-exposed (EITE) customers. Pub. Util. Code Section 748.5(c) also provided authority to the Commission to allocate up to 15% of those revenues through June 2026 to clean energy and energy efficiency programs. (There is no corollary code section providing authority or direction applicable to the natural gas utilities’ revenues; there, CARB regulations and Commission decisions govern.) The Commission implements and establishes its guidance in compliance with CARB’s regulations. As of early 2026, CARB is in the process of developing new regulations for Cap-and-Invest in compliance with AB 1207: on January 13, 2026, CARB made publicly available its proposed amendments to the Cap-and-Invest Regulation and its Initial Statement of Reasons. The instant proceeding is therefore phased to consider issues expected to be affected by these ongoing 2 This amount increases 5% per year. In 2026 natural gas utilities were required to consign 80% of freely allocated allowances.
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changes in Phase 2, to allow CARB to complete its new regulations before we implement them.
In numerous decisions throughout R.10-05-006 and R.11-03-012 (for the electric utilities) and R.14-03-003 (for natural gas utilities) the Commission adopted rules and other guidance for the forecasting, distribution, and outreach related to allowance revenues. The electric utilities return the revenues in the form of the California Climate Credit for residential customers, the Small Business Climate Credit to small businesses, and the Industry Assistance Credit for eligible “emissions-intensive and trade-exposed” (EITE) industrial customers.
The gas utilities return proceeds to residential gas customers in the form of the California Climate Credit.
In various other proceedings and decisions, the Commission approved uses for the 15% of revenues described in Pub. Util. Code Section 748.5(c). As specifically directed by AB 693,3 the largest share of funds allocated pursuant to this code section go to the Solar on Multifamily Affordable Housing (SOMAH) program.4
As mentioned above, in 2025 AB 1207 extended the Cap-and-Invest Program and made a number of changes relevant to the Utilities’ allowance revenues. The requirement to credit electric revenues to small business and EITE customers was removed from Pub. Util. Code Section 748.5(a), but Pub. Util.
Code Section 748.5(a)(2) was added specifying that the Commission can still continue to do so.
3 AB 693 (codified in Pub. Util. Code Section 2870)
4 SOMAH was established in D.17-12-022, as modified by D.19-03-015, in R.14-07-002.
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Additionally, AB 1207 added Pub. Util. Code Section 748.5(a)(3) requiring electric credits to be provided “in no more than four high-billed months of each year to maximize customer electric bill affordability, or as otherwise directed by the Commission to address extreme, unforeseen, and temporary circumstances.”5 AB 1207 also clarified that Pub. Util. Code Section 748.5(c) regarding the Commission’s 15% clean energy set-aside authority would become inoperative on July 1, 2026. The instant Rulemaking will not consider issues related to the discontinuance of the Commission’s authority in Pub. Util. Code Section 748.5(c) and related programs, since those issues are already in scope of R.25-01-005.
However, this proceeding will address another new provision created by AB 1207: Pub. Util. Code Section 748.5(d)(1), which states that the Commission will require 5 percent of the electric utilities’ revenues to be remitted annually to the State Treasury for deposit in the California Transmission Accelerator Revolving Fund.
6 This code section becomes operative July 1, 2026 and applies for five years.
Finally, AB 1207 added Pub. Util. Code Section 748.5(b), requiring the Commission by January 1, 2027, to direct the electric utilities to update their outreach plans to include a statement about their Climate Credit savings “at the top of customer bills,” attributing those savings to the Cap-and-Invest Program.
The following parties filed opening and/or reply comments on the OIR:
Bear Valley Electric Service, Inc., jointly with Liberty Utilities (CalPeco Electric) LLC, and PacifiCorp (the Joint Small and Multijurisdictional Utilities or Joint SMJUs); the Public Advocates Office; the California Community Choice 5 Pub. Util. Code Section 748.5(a)(3).
6 Established in 2025 by SB 254 to support critical energy infrastructure projects.
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Association (CalCCA); California Farm Bureau Federation; California Large Energy Consumers Association (CLECA); Center for Accessible Technology; Center for Sustainable Energy; Coalition of California Utility Employees; Energy Producers and Users Coalition; Natural Resources Defense Council; Pacific Gas and Electric Company; Pacific Steel Group; San Diego Gas & Electric Company; Small Business Utility Advocates (SBUA); Southern California Edison Company (SCE); Southern California Gas Company (SoCalGas); and The Utility Reform Network (TURN). The California Environmental Justice Alliance (CEJA), Central California Asthma Collaborative (CCAC), Central California Environmental Justice Network (CCEJN), and Leadership Counsel for Justice and Accountability (LCJA) filed motions for party status that were granted by the Administrative Law Judge (ALJ).
A prehearing conference (PHC) was held on November 21, 2025 to address the issues of law and fact, determine the need for hearing, set the schedule for resolving the matter, and address other matters as necessary. On December 8, 2026, the following parties filed post-PHC statements: CalCCA; CCAC; CEJA, CCAJN, and LCJA (jointly); CLECA; the Joint SMJUs; Pacific Steel; PG&E; SBUA; SCE; SDG&E; SoCalGas; and TURN.
After considering parties’ comments on the OIR, input at the PHC, and post-PHC statements, I have determined the issues and initial schedule of the proceeding to be set forth in this scoping memo.
2. Issues
This scoping memo sets the scope for Phase 1. This phase will consider issues only related to the residential Climate Credit and not issues related to the Small Business Climate Credit or Industry Assistance Credit. Phase 2 will be scoped at a later date and is expected to include other issues related to the
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Utilities’ allowance revenues as well as implementation of changes in CARB’s regulations.
The issues to be determined or otherwise considered are:
Phase 1A Issues: Pausing the 2026 Residential Electric Climate Credit and Considering Other Immediate Affordability Improvements
1. Whether the Commission should order the large electric utilities to pause the distribution of the 2026 residential Climate Credits while considering other issues in this
phase.
2. Whether the Commission should make immediate changes to the residential gas and electric Climate Credit to
maximize affordability, and whether these changes should be interim pending consideration of issues in Phase 1B.
3. How should the Commission implement the transfer of 5 percent of revenues to the State Treasury for deposit in the California Transmission Accelerator Revolving Fund in
compliance with Pub. Util. Code Section 748.5(d).
4. How should the Commission implement Pub. Util. Code
Section 748.5 (b)(2), regarding Climate Credit outreach.
Phase 1B Issues: Broader Consideration of Changes to the Residential Climate Credit
1. Whether the Commission should change or establish
guiding principles, goals, and/or objectives for the
residential Climate Credit.
2. Whether the Commission should make changes to the
residential Climate Credit, including changes to credit eligibility, timing of distribution, number of annual
distributions, and/or calculation methodology for Climate Credit amounts.
3. Whether the Commission should direct changes to Climate Credit outreach.
4. Whether the time and cost to implement changes, and
other impacts of changes to the residential Climate Credit, are reasonable.
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5. Whether the Commission should authorize additional costs related to changes directed in this proceeding.
6. Whether the impacts of the residential Climate Credit changes on environmental and social justice communities are reasonable, including the extent to which these changes impact the achievement of any of the nine goals of the
Commission’s Environmental and Social Justice Action
Plan.
3. Need for Evidentiary Hearing
Parties have not identified any potentially contested material issues of fact, although multiple parties indicated that these issues could arise. Accordingly, I determine that evidentiary hearings are not needed. Parties may request hearings, and a future ruling may set a deadline to do so. The need for evidentiary hearing will be determined by the assigned ALJ and further instructions provided at a status conference if hearings are necessary.
4. Schedule
In alignment with statutory deadlines and the need to improve the affordability benefit of the Climate Credit for customers, this proceeding will be completed in at least two phases. The issues in Phase 1 are complex and require fast action from the Commission and parties; some of these issues must be addressed extremely quickly. For this reason, Phase 1 will be resolved in three decisions and will focus on the residential electric and natural gas Climate Credit. The Small Business Climate Credit and Industry Assistance Credit will not be addressed in Phase 1.
The Phase 1A schedules are adopted here and may be modified by the ALJ as required to promote the efficient and fair resolution of the rulemaking.
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4.1. Phase 1A: Pausing the Spring 2026 Residential
Electric Climate Credit and Considering Other
Immediate Affordability Improvements
Phase 1A will be resolved in two decisions. In the first, the Commission will consider only Issue 1 within Phase 1A, regarding whether to pause the distribution of the large electric utilities’ 2026 residential Climate Credits.
As noted above, Pub. Util. Code Section 748.5(a)(3) provides guidance to maximize customer affordability, requiring that the electric Climate Credits “shall be provided on the bills of those customers in no more than four high-billed months of each year to maximize customer electric bill affordability, or as otherwise directed by the commission to address extreme, unforeseen, and temporary circumstances.” In response to this statutory direction, and in line with the scope of issues being considered in Phase 1A, I intend to issue a proposed decision (PD) as soon as possible – and no later than February 13, 2026 – that directs the large electric utilities (PG&E, SCE and SDG&E) to pause the distribution of the 2026 residential Climate Credits. I intend for this “Pause PD” to order the large electric utilities to hold off on delivering the credits pending the second decision in Phase 1A that addresses whether moving the 2026 Climate Credits to a high-billed month or months would benefit customer affordability.
The scope of Issue 1 does not include the SMJUs because the record indicates that their customers are less likely to benefit from an immediate pause, as the SMJUs stated at the PHC and in their Post-PHC statements: “While high-billed months for much of the state coincides with warm summer months, the winter peaking nature of the SMJUs dictates that SMJU Climate Credits should be distributed closer to winter.”7 Additionally, both Pacificorp and Liberty do 7 SMJU Post-PHC Statement at 2.
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not have approved 2026 Climate Credits as of the issuance of this scoping ruling.
The scope of Issue 1 also does not include the gas utilities because their next residential credit occurring after March 2026 will be distributed in 2027; there is no immediate need to address distribution timing for 2027 credits in the Pause PD.
The schedule for the Pause PD, which will only address Phase 1A Issue 1, is below.
Schedule for Addressing Issue 1 within Phase 1A
Event Date
Pause PD issued As soon as possible and no later
than February 13, 2026
Parties file comments on
Pause PD
20 days after the issuance of the
Pause PD
Parties file reply comments
on Pause PD
27 days after the issuance of the
Pause PD
Commission Vote on Pause
PD March 19, 2026
In a second Phase 1A PD, following closely after the Pause PD, we will address the remaining issues in Phase 1A.
One factor affecting this proceeding’s schedule is the process by which annual Climate Credit amounts are forecasted and approved. The large electric utilities forecast their allowance revenues and resulting Climate Credit amounts in annual Energy Resource Recovery Account (ERRA) Forecast applications.
These applications are filed in April and May and are generally resolved by December each year; the Commission’s authorization of the next year’s Climate Credit is an important and necessary milestone. Corollary processes for the
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SMJUs occur in their Energy Cost Adjustment Clause applications, although on a different cadence.
Key forecast updates in the ERRA process occur as part of the October Update filings. Therefore, any changes to the Climate Credit that would apply in 2027 would need to be finalized well before October 2026 to be reflected in the October Update. Because broader changes in Phase 1B are not expected to be final by then, we will consider whether to apply Phase 1A changes in 2027 as well as 2026.
A schedule for addressing the remaining Phase 1A issues is below. Parties have identified time constraints on any changes made to the residential Climate Credit that could take effect and deliver immediate affordability relief in 2026, but one possibility discussed at the PHC was moving the fall credit up to August or September 2026. Due to the limited time remaining before the fall Climate Credit, this ruling requires the Utilities, and allows other parties, to submit comments responding to the questions in Section 4.2 of this scoping memo and ruling.
Schedule for Addressing Phase 1A Issues 2, 3, and 4
Event Date
Parties file opening comments
responding to questions in
Section 4.2
March 2, 2026
Parties file reply comments to
Phase 1A comments
March 9, 2026
Phase 1A PD issued for party
comment
No later than March 27, 2026
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Parties file opening comments
on Phase 1A PD
20 days after the issuance of the
Phase 1A PD
Parties file reply comments on
Phase 1A PD
27 days after the issuance of the
Phase 1A PD
Commission Vote on Phase 1A
PD
April 30, 2026
4.2. Phase 1A Questions for Party Comment
This ruling directs the Utilities, and authorizes all other parties, to file and serve comments responding to the following questions with respect to the residential Climate Credit and other issues within Phase 1A:
1. What immediate changes can be made to the residential electric and gas Climate Credit in the near term to improve its affordability impact while this proceeding considers broader, permanent changes to Climate Credit
methodologies, eligibility, distribution, and other factors?
2. Current timing of the residential Climate Credit is based on a basic assumption that spring and fall are relatively low energy usage seasons, and that awareness of the credit
would be maximized if delivered at this time; the primary objective has not been focused on affordability impacts.
Given the Legislature’s mandate to maximize affordability, should the Commission order the utilities to move up the fall 2026 electric residential Climate Credit, delivering it instead as a summer Climate Credit in August or
September 2026?
3. If the Commission approves the pause in the distribution of the residential electric 2026 Climate Credit, should it order the spring credit to instead be delivered in summer 2026 as well? Since Climate Credit amounts are set, should the two 2026 credits be delivered in August and
September, respectively?
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4. Would it benefit customer affordability for the
Commission to order the spring 2027 gas Climate Credit to instead be delivered as a winter credit in February 2027?
5. Should the Commission order any other changes to the residential Climate Credit to maximize affordability that can take effect in 2026?
6. Due to timelines driven by ERRA proceedings, should
changes to the residential electric Climate Credit made in Phase 1A also apply for 2027, such that these interim
benefits may be experienced in that year as well?
7. Should Phase 1A changes be explicitly designated as
interim, applicable only until the resolution of Phase 1B and without prejudice to any of the broader changes being considered in that phase?
8. What specific direction and authority do the utilities need to implement the immediate affordability actions approved in Phase 1A?
9. What outreach changes are possible for Phase 1A
immediate affordability actions? Should the Commission
require messaging delivered in 2026 to refer to the Cap-and-Invest Program?
10.What direction must the Commission give to ensure
compliance with Pub. Util. Code Section 748.5 (b)(2),
regarding updates to the customer outreach plan?
a. How should “the top of customer bills” be defined and implemented, in line with this code section? What
billing limitations exist?
b. For customers who receive paper bills, do bill inserts placed on top of paper bills qualify? What placement
complies for e-billed customers?
c. How can other outreach be aligned with these messages in line with the spirit of this code section?
d. What approval process should apply to these updates to outreach? What new authority, if any, should be
delegated to Commission staff?
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11.What direction do the utilities need to effectuate the transfer of 5% of revenues to the State Treasury for deposit in the California Transmission Accelerator Revolving Fund pursuant to Pub. Util. Code Section 748.5(d)? What
documentation should the Utilities provide to the
Commission demonstrating their transmittal of the funds annually? Overall, what action must the Commission take to ensure compliance with this code section?
4.3. Phase 1B: Broader Consideration of Changes to
the Residential Climate Credit
Out of necessity, the first several months of this proceeding will be focused on Phase 1A, but we will soon turn our focus to the broader improvements and changes to the residential Climate Credit that are in scope of Phase 1B. While the scope of issues to be considered in Phase 1B is set in this scoping memo, the schedule of events and dates for doing so is not. This schedule is forthcoming, but I expect it to consist of the following:
• A proposed schedule, followed by a status conference in spring 2026, to discuss and clarify the schedule;
• One or more rulings requesting party comments
addressing Phase 1B issues and directing the utilities to provide the needed data;
• Parties present proposal concepts at a workshop, and by late summer 2026 submit proposals for how to change the Climate Credit;
• Further refinement of proposals and ideas, including a second workshop and utility assessment of the time and
other impacts of parties’ proposals; and
• Briefs and reply briefs.
Overall, I expect Phase 1 to be submitted by late 2026, providing time for a Phase 1B PD by the first quarter of 2027. This timeline will allow for ample implementation ahead of that year’s ERRA and ECAC filings.
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The proceeding will stand submitted upon the filing of reply briefs unless the ALJ requires further evidence or argument. Based on this schedule, the proceeding will be resolved within 18 months as required by Public Utilities Code Section 1701.5.
5. Alternative Dispute Resolution (ADR) Program and
Settlements
The Commission’s Alternative Dispute Resolution (ADR) program offers mediation, early neutral evaluation, and facilitation services, and uses ALJs who have been trained as neutrals. At the parties’ request, the assigned ALJ can refer this proceeding to the Commission’s ADR Coordinator. Additional ADR information is available on the Commission’s website.8
Any settlement between parties, whether regarding all or some of the issues, shall comply with Article 12 of the Rules and shall be served in writing.
Such settlements shall include a complete explanation of the settlement and a complete explanation of why it is reasonable in light of the whole record, consistent with the law and in the public interest. The proposing parties bear the burden of proof as to whether the settlement should be adopted by the Commission.
Any settlements between parties, whether regarding all or some of the issues, shall comply with Article 12 of the Rules and shall be served in writing.
Such settlements shall include a complete explanation of the settlement and a complete explanation of why it is reasonable in light of the whole record, consistent with the law, and in the public interest. The proposing parties bear the burden of proof as to whether the settlement should be adopted by the Commission.
8 https://www.cpuc.ca.gov/PUC/adr/
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6. Category of Proceeding and Ex Parte Restrictions
This rulemaking was preliminarily categorized as quasi-legislative (QL). In comments on the OIR and at the PHC, a number of parties provided comment on categorization, with some stating agreement with the QL categorization and some arguing for a ratesetting categorization. Some in the latter category, including Cal Advocates, argued that the proceeding should be ratesetting because it will have an effect on rates. Others disagreed, stating that this is a policymaking proceeding rightfully categorized as QL.
This ruling confirms the Commission’s preliminary determination9 that this is a quasi-legislative proceeding. The Climate Credit is a bill credit, entirely separate from rates; it does impact overall bills and affordability. Additionally, this is a broad policymaking proceeding focused on overall goals and benefits impacting the customers of numerous energy utilities in the state. A QL categorization is appropriate.
Accordingly, ex parte communications are permitted without restriction or reporting requirement pursuant to Article 8 of the Rules.
7. Public Outreach
Pursuant to Public Utilities Code Section 1711(a), where feasible and appropriate, before determining the scope of the proceeding, the Commission sought the participation of those likely to be affected, including those likely to derive benefit from, and those potentially subject to, a decision in this proceeding. This matter was noticed on the Commission’s daily calendar. Where feasible and appropriate, this matter was incorporated into engagements 9 OIR at page 6.
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conducted by the Commission’s External Affairs Division with local governments and other interested parties.
The OIR was served to all core transport agents and the following proceedings’ service lists: Rulemaking (R.) 14-03-003 (Natural Gas Utility Cost Issues Associated with Greenhouse Gas Emissions); R.22-07-005 (Demand Flexibility Rates); R.20-05-002 (Climate Credits); R.14-07-002 (Net Energy Metering); Application (A.) 24-09-014 (PG&E General Rate Case Phase 2); A.24- 03-019 (SCE General Rate Case Phase 2); A.23-01-008 (SDG&E General Rate Case Phase 2); R.18-07-005 (Residential Disconnections); A.24-09-001 (Southwest Gas Company General Rate Case); A.24-09-010 (Liberty Utilities General Rate Case); A.22-08-010 (Bear Valley Electric Service General Rate Case); and A.22-05-006 (PacifiCorp General Rate Case).
8. Intervenor Compensation
Pursuant to Public Utilities Code Section 1804(a)(1), a customer who intends to seek an award of compensation must file and serve a notice of intent to claim compensation by December 21, 2026, 30 days after the prehearing conference.
9. Response to Public Comments
Parties may, but are not required to, respond to written comments received from the public. Parties may do so by posting such response using the “Add Public Comment” button on the “Public Comment” tab of the online docket card for the proceeding.
10. Public Advisor
Any person interested in participating in this proceeding who is unfamiliar with the Commission’s procedures or has questions about the electronic filing procedures is encouraged to obtain more information at
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https://www.cpuc.ca.gov/about-cpuc/divisions/news-and-public-information-office/public-advisors-office or contact the Commission’s Public Advisor at 866- 849-8390 or 866-836-7825 (TTY), or send an e-mail to [email protected].
11. Filing, Service, and Service List
The official service list has been created and is on the Commission’s website. Parties should confirm that their information on the service list is correct and serve notice of any errors on the Commission’s Process office, the service list, and the ALJ. Persons may become a party pursuant to Rule 1.4. 10 When serving any document, each party must ensure that it is using the current official service list on the Commission’s website.
This proceeding will follow the electronic service protocol set forth in Rule
1.10. All parties to this proceeding shall serve documents and pleadings using electronic mail, whenever possible, transmitted no later than 5:00 p.m., on the date scheduled for service to occur.
While Rule 1.10 requires service on the ALJ of both an electronic and a paper copy of filed or served documents, parties to this rulemaking are specifically instructed not to serve paper copies of filed or served documents on the ALJ. Filed documents should be electronically served only to the ALJ.
When serving documents on Commissioners or their personal advisors, whether or not they are on the official service list, parties must only provide electronic service. Parties must not send hard copies of documents to Commissioners or their personal advisors unless specifically instructed to do so. 10 The form to request additions and changes to the Service list may be found at https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/additiontoservicelisttranscriptordercompliant.pdf
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Persons who are not parties but wish to receive electronic service of documents filed in the proceeding may contact the Process Office at [email protected] to request addition to the “Information Only” category of the official service list pursuant to Rule 1.9(f).
The Commission encourages those who seek information-only status on the service list to consider the Commission’s subscription service as an alternative. The subscription service sends individual notifications to each subscriber of formal e-filings tendered and accepted by the Commission. Notices sent through subscription service are less likely to be flagged by spam or other filters. Notifications can be for a specific proceeding, a range of documents and daily or weekly digests.
12. Receiving Electronic Service from the Commission
Parties and other persons on the service list are advised that it is the responsibility of each person or entity on the service list for Commission proceedings to ensure their ability to receive emails from the Commission.
Please add “@cpuc.ca.gov” to your email safe sender list and update your email screening practices, settings and filters to ensure receipt of emails from the Commission.
13. Assignment of Proceeding
President Alice Reynolds is the assigned commissioner and ALJ Maria Sotero is the assigned ALJ for the proceeding.
IT IS RULED that:
1. The scope of this proceeding is described above and is adopted.
2. The schedule of this proceeding is set forth above and is adopted.
3. Bear Valley Electric Service, Liberty Utilities (CalPeco Electric), LLC, Pacific Gas and Electric Company, Pacificorp, San Diego Gas & Electric
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Company, Southern California Edison Company, Southern California Gas Company, and Southwest Gas Company are directed to file and serve comments entitled Phase 1A Opening Comments not exceeding 15 pages responding to all of the questions in Section 4.2 of this ruling no later than March 2, 2026.
4. All other parties are authorized to file and serve comments entitled Phase 1A Opening Comments not exceeding 15 pages responding to any of the questions in Section 4.2 of this ruling no later than March 2, 2026.
5. Parties are authorized to file and serve Phase 1A Reply Comments not exceeding 10 pages responding to March 2 comments no later than March 9, 2026.
6. Evidentiary hearing is not needed.
7. The category of the proceeding is quasi-legislative.
Dated February 3, 2026, at San Francisco, California.
/s/ ALICE REYNOLDS
Alice Reynolds
Assigned Commissioner