cc 2023 AR 10/24 ab 205 — Vista City Council, October 24, 2023

ACTION:

Clerk/Secretary
Department: City Manager Item No: D3
Prepared by: Imelda M. Huerta, Assistant City Manager Meeting Date: October 24, 2023 Approved by: John Conley, City Manager Agenda Location: Discussion SUBJECT: OPPOSE FIXED ENERGY CHARGES AUTHORIZED IN ASSEMBLY BILL 205 ENERGY 2021-2022).

RECOMMENDATION:

1.Discuss the fixed energy charges authorized in Assembly Bill (AB) 205 Energy (2021-2022); and

2. Adopt City Council Resolution No. 2023- , opposing the fixed energy charges authorized in Assembly Bill (AB) 205 Energy (2021-2022).

CORRELATION TO CITY COUNCIL GOALS: Fiscal Responsibility PRIOR ACTION: None
STATEMENT ON THE SUBJECT: Councilmember O’Donnell requested the City Manager place a discussion item on an upcoming agenda to discuss the fixed energy charges authorized in Assembly Bill AB) 205 Energy (2021-2022) as noted in Exhibit 1; and requests the adoption of a resolution opposing the fixed charges and urging the California Public Utilities Commission (CPUC) not implement these fixed charges.

The bill text is included as Exhibit 2, and the proposal to the CPUC is included as Exhibit 3 for reference.

FISCAL IMPACT: There is no direct fiscal impact associated with this discussion item.

EXHIBITS:

1.City Council Resolution No. 2023- , opposing the fixed energy charges authorized in Assembly Bill AB) 205 Energy (2021-2022).

2.AB 205 Energy (2021-2022) Bill Text

3. Proposal to the California Public Utilities Commission (CPUC) AGENDA
REPORT

CITY COUNCIL

COMMUNITY DEVELOPMENT COMMISSION

SUCCESSOR AGENCY

BUENA SANITATION DISTRICT

JOINT POWERS FINANCING AUTHORITY
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Approved above recommendation, adopted City Council Resolution No. 2023-186.

Vote: 5-0

00029213 7
RESOLUTION NO. 2023-

A RESOLUTION OF THE CITY COUNCIL OF THE CHARTERED CITY OF

VISTA, CALIFORNIA, OPPOSING THE FIXED ENERGY CHARGES
AUTHORIZED IN ASSEMBLY BILL 205 ENERGY (2021-2022)
The City Council of the City of Vista does resolve as follows:

1. Findings. The City Council hereby finds and declares the following:

A. Assembly Bill (AB) 205 Energy (2021-2022) was signed into law by California Governor Newsom on June 30, 2022.

B. This bill contains a variety of energy measures. The City objects to one specific provision of AB 205. Specifically, AB 205 repeals the existing $10 fixed charge cap for residential investor-owned utility customers and authorizes the California Public Utilities Commission (CPUC) to use fixed charges for any rate schedule for residential customers.

C. The bill requires the fixed charge to be established on an income-graduated basis with no fewer than three income thresholds. In other words, electric utility customers would be paying a fixed charge based on income and not electricity usage.

D. This fixed charge provision of AB 205 was inserted into the bill without debate or discussion. The fixed charge provision of AB 205 was not justified by any facts or empirical evidence before its passage by the State.

2. Action.

A. The City Council opposes the fixed energy charges authorized in AB 205 and urges the CPUC to not implement these fixed charges.

B. The City Council further resolves that the City Manager, or designee, continue to advocate for the repeal of AB 205’s income-based fixed charges.

3. Adoption. PASSED AND ADOPTED at a meeting of the City Council of the City of Vista held on October 24, 2023, by the following vote:

AYES:

NOES:

ABSTAIN:

APPROVED AS TO FORM:

WALTER CHUNG, CITY ATTORNEY
By:

APPROVED
Walter C. Chung
20231016142222

JOHN FRANKLIN, MAYOR
ATTEST:

KATHY VALDEZ, CITY CLERK
By:
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EXHIBIT 1

Assembly Bill No. 205
CHAPTER 61
An act to add Article 13 (commencing with Section 16429.8) to Chapter 2 of Part 2 of Division 4 of Title 2 of the Government Code, to amend Sections 25403.2 and 25806 of, to add Chapter 6.2 (commencing with Section 25545), Chapter 7.4 (commencing with Section 25640), and Chapter

8.9 (commencing with Section 25790) to Division 15 of, and to add and repeal Section 25216.8 of, the Public Resources Code, to amend Sections 381, 739.1, 739.9, and 2827.1 of the Public Utilities Code, to add and repeal Section 17131.20 of the Revenue and Taxation Code, and to add Division 29 (commencing with Section 80700) to the Water Code, relating to energy, and making an appropriation therefor, to take effect immediately, bill related to the budget.
[Approved by Governor June 30, 2022. Filed with Secretary of State June 30, 2022.]
legislative counsel’s digest
AB 205, Committee on Budget. Energy.
(1) Existing law, until January 1, 2026, establishes the California Arrearage Payment Program (CAPP) within the Department of Community Services and Development. Existing law requires the department to survey utility applicants to obtain data pertaining to the total number of residential and commercial customer accounts in arrears to determine the total statewide energy utility arrearage and to develop an allocation formula for determining an individual utility applicant’s share of CAPP funds. Existing law authorizes speciﬁed utilities to apply for CAPP funds on behalf of their customers, and requires the utility to use any funds received to offset customer arrearages that were incurred during the COVID-19 pandemic bill relief period, as speciﬁed. Existing law prohibits service from being discontinued due to nonpayment for those customers included in a utility’s CAPP application while the department reviews and approves all pending CAPP applications, and requires the utility applicant to waive any associated late fees and accrued interest for customers who are awarded CAPP beneﬁts. Existing law requires the department to report speciﬁed data to the Legislature and on its public-facing internet website relating to distribution of CAPP beneﬁts.

This bill would, upon appropriation, establish the 2022 California Arrearage Payment Program (2022 CAPP) within the Department of Community Services and Development. The bill would require the department to release program notices and post program notices related to 2022 CAPP administration on its public-facing internet website. The bill would require the department to make available an online application for utility applicants to request 2022 CAPP funding for residential customers. 95 STATE OF CALIFORNIA

AUTHENTICATED

ELECTRONIC LEGAL MATERIAL
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EXHIBIT 2

The bill would require the department to develop an allocation formula for determining an individual utility applicant’s share of 2022 CAPP funds based on the proportional share of the total statewide energy utility arrearages. The bill would require the department to approve utility applicant’s 2022 CAPP applications, set statewide allocations, and disburse funds within 7 months of the appropriation for the CAPP.

This bill would require a utility applicant to issue 2022 CAPP beneﬁts to residential customers within 60 days of receiving 2022 CAPP funds. The bill would require a utility applicant to submit all reporting required by the department detailed in a program notice within 6 months of the utility applicant’s receipt of its 2022 CAPP allocation. The bill would require the department to report speciﬁed data to the Legislature and on its public-facing internet website relating to distribution of 2022 CAPP beneﬁts within 60 days of receiving reporting from utility applicants.

This bill would require that any payment authorized by the 2022 CAPP be treated in the same manner as the federal earned income refund for purposes of determining the individual’s eligibility to receive beneﬁts under speciﬁed public social services laws. The bill would also prohibit the payment from being taken into account as resources for a period of 12 months from receipt, for purposes of determining the eligibility of the individual, or any other individual, for beneﬁts or assistance for any other state or local program, as provided.
(2) Existing law requires the State Energy Resources Conservation and Development Commission (Energy Commission) to undertake various actions in furtherance of meeting the state’s clean energy and pollution reduction objectives.

This bill would require the Energy Commission to establish and implement the Long-Duration Energy Storage Program to provide ﬁnancial incentives for projects that have power ratings of at least one megawatt and are capable of reaching a target of at least 8 hours of continuous discharge of electricity in order to deploy innovative energy storage systems to the electrical grid for purposes of providing critical capacity and grid services. The bill would authorize the Energy Commission to adopt guidelines or other standards for, use ﬁnancial incentives to provide moneys to participants in, and provide technical assistance for, that program. The bill would authorize the Energy Commission to noncompetitively award moneys for that program under speciﬁed circumstances.

Existing law vests the Energy Commission with the exclusive jurisdiction to certify the construction of a stationary or ﬂoating electrical generating facility using a source of thermal energy with a generating capacity of 50 megawatts or more. Existing law prohibits a person from constructing such a facility unless that person obtains a certiﬁcate from the commission, as provided.

The California Environmental Quality Act (CEQA) requires a lead agency, as deﬁned, to prepare, or cause to be prepared, and certify the completion of an environmental impact report on a project that it proposes to carry out or approve that may have a signiﬁcant effect on the environment or to adopt 95 —2 — Ch. 61
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a negative declaration if the lead agency ﬁnds that the project will not have that effect. CEQA also requires a lead agency to prepare a mitigated negative declaration for a project that may have a signiﬁcant effect on the environment if revisions in the project would avoid or mitigate that effect and there is no substantial evidence that the project, as revised, would have a signiﬁcant effect on the environment.

The Jobs and Economic ImprovementThrough Environmental Leadership Act of 2021 authorizes the Governor, until January 1, 2024, to certify a leadership project, as deﬁned, that meets speciﬁed requirements for streamlining beneﬁts related to CEQA, as provided. The act authorizes a person proposing to construct a leadership project to apply to the Governor for certiﬁcation that the leadership project is eligible for streamlining pursuant to the act.

This bill would establish a new certiﬁcation process for a solar photovoltaic, terrestrial wind electrical generation powerplant, or thermal powerplant that does not use fossil or nuclear fuels, with a generating capacity of 50 megawatts or more, an energy storage system capable of storing 200 megawatthours or more of electricity, an electric transmission line from those generating or storage facilities to a point of junction with an interconnected electrical transmission system, or a facility for the manufacture, production, or assembly of energy storage systems or their components, wind systems or their components, solar photovoltaic systems or their components, or specialized products, components, or systems that are integral to renewable energy or energy storage technologies with a capital investment of at least $250,000,000 over a period of 5 years. The bill would authorize a person proposing to construct those facilities, no later than June 30, 2029, to ﬁle an application for certiﬁcation with the Energy Commission.

The bill would require the Energy Commission to review the application, as provided, and to determine whether to issue the certiﬁcation within a speciﬁed time period. The bill would require the Energy Commission to forward the application to a local government having land use and related jurisdiction in the areas of the proposed site and related facility and would require the local agencies to review the application and submit comments on the application, as provided, thereby imposing a state-mandated local program. The bill would authorize local agencies to request a fee from the Energy Commission to reimburse the local agency for the actual and added costs of the review by the local agency. The bill would prohibit the Energy Commission from issuing the certiﬁcate unless the Energy Commission makes certain ﬁndings. The bill would, except as provided, specify that the issuance of the certiﬁcation is in lieu of any permit, certiﬁcate, or similar document required by a state, local, or regional agency, or federal agency, to the extent permitted by federal law, for those facilities. The bill would designate the Energy Commission as the lead agency for purposes of CEQA in regards to the certiﬁcation decision. The bill would specify procedures by which the Energy Commission is to conduct the environmental review for its certiﬁcation decision. The bill would provide that a facility certiﬁed under these provision is a certiﬁed leadership project under the Jobs and 95 Ch. 61—3 —
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Economic Improvement Through Environmental Leadership Act of 2021, without the need for any action from the applicant or the Governor, if the commission makes certain ﬁndings and takes certain actions. The bill would require the Judicial Council to adopt a rule of court to establish procedures that require actions or proceedings related to the certiﬁcation of an environmental impact report or the issuance of the certiﬁcation for any site and related facility to be resolved within 270 days, and, if the Jobs and Economic Improvement Through Environmental Leadership Act of 2021 is inoperative or repealed, would require those procedures to become operative.
(3) This bill would require the Energy Commission to implement and administer the Distributed Electricity Backup Assets Program to incentivize the construction of cleaner and more efﬁcient distributed energy assets that would serve as on-call emergency supply or load reduction for the state’s electrical grid during extreme events, as provided. The bill would require the Energy Commission to implement and administer the Demand Side Grid Support Program to incentivize dispatchable customer load reduction and backup generation operation as on-call emergency supply and load reduction for the state’s electrical grid during extreme events, as provided. The bill would create the Strategic Reliability Reserve Fund, and the Distributed Electricity Backup Assets Account and the Demand Side Grid Support Account in the fund. The bill would continuously appropriate to the Energy Commission moneys in the fund for purposes of adding resources to the electrical grid to ensure electrical grid reliability and support the clean energy transition, thereby making an appropriation. The bill would continuously appropriate moneys into the accounts to the Energy Commission for the implementation of the above-described programs, respectively, thereby making an appropriation.

This bill would require the Department of Water Resources, in consultation with the Energy Commission, to implement those projects, purchases, and contracts to carry out the above-described purposes. The bill would provide that CEQA does not apply to contracts entered into, or approval granted by, the department to implement those projects, purchases, and contracts. The bill would establish the Department of Water Resources Electricity Supply Reliability Reserve Fund and would continuously appropriate moneys in the fund to the Department of Water Resources to cover the costs incurred by the department in the implementation of the bill, thereby making an appropriation.

This bill would, until July 1, 2027, vest the Energy Commission with the exclusive jurisdiction to certify sites on which facilities for actions described above that are undertaken by the department are proposed to be located.

The bill would require the department to submit an application for certiﬁcation for those sites, as provided. The bill would require the Energy Commission to establish a process to expedite the review of an application, as provided, and to determine whether to issue the certiﬁcation within a speciﬁed time period. The bill would prohibit the certiﬁcation of a site under 95 —4 — Ch. 61
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certain circumstances. The bill would exempt from CEQA the certiﬁcation of a site and related facilities by the Energy Commission. (4) Existing law vests the Public Utilities Commission (PUC) with regulatory authority over public utilities, including electrical corporations.

Existing law requires the PUC to require each electrical corporation to identify a separate rate component to collect revenues used to fund certain programs. Existing law requires the rate component to be a nonbypassable element of local distribution service and collected on the basis of usage.

This bill would repeal the requirement that the nonbypassable element be collected on the basis of usage.

Existing law requires the PUC to continue the California Alternative Rates for Energy (CARE) program to provide assistance to low-income electric and gas customers with annual household incomes that are no greater than 200% of the federal poverty guideline levels. For electrical corporations with 100,000 or more customer accounts, existing law requires the PUC to ensure, among other things, that the average effective CARE discount is not less than 30% or more than 35% of the revenues that would have been produced for the same billed usage by non-CARE customers and that the average effective discount, as determined by the PUC, reﬂects any charges not paid by CARE customers.

This bill would instead require that the average effective discount, as determined by the PUC, not reﬂect any charges for which CARE customers are exempted, discounts to ﬁxed charges or other rates paid by non-CARE customers, or bill savings resulting from participation in other programs.

Existing law authorizes the PUC to adopt new, or expand existing, ﬁxed charges, as deﬁned, for the purpose of collecting a reasonable portion of the ﬁxed costs of providing electric service to residential customers. Existing law requires the PUC to require each electrical corporation to offer default rates to residential customers with at least two usage tiers, as provided.

Existing law requires the PUC to ensure that the approved charges do not, among other things, unreasonably impair incentives for conservation and energy efﬁciency. Existing law authorizes the PUC to authorize ﬁxed charges that do not exceed certain amounts per residential customer account per month, as provided.

This bill would delete the requirement that each electrical corporation offer default rates to residential customers with at least two usage tiers. The bill would additionally require the PUC to ensure that the approved ﬁxed charges do not unreasonably impair incentives for beneﬁcial electriﬁcation and greenhouse gas reduction. The bill would instead authorize the PUC to authorize ﬁxed charges for any rate schedule applicable to residential customer accounts. The bill would eliminate the cap on the amount of the ﬁxed charge that the PUC may authorize. The bill would require the ﬁxed charge to be established on an income-graduated basis, as provided, with no fewer than 3 income thresholds so that low-income ratepayers in each baseline territory would realize a lower average monthly bill without making any changes in usage. The bill would require the PUC, no later than July 1, 2024, to authorize a ﬁxed charge for default residential rates. The bill would 95 Ch. 61—5 —
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prohibit the PUC from applying the composite tier method to the treatment of any revenues resulting from any ﬁxed charge adopted pursuant to these provisions.

Under existing law, a violation of the Public Utilities Act or any order, decision, rule, direction, demand, or requirement of the PUC is a crime.

Because the provisions of this bill are within the act and require action by the PUC to implement their requirements, a violation of these provisions would impose a state-mandated local program.
(5) The Personal Income Tax Law and the Corporation Tax Law, in conformity with federal income tax law, generally deﬁne “gross income” as income from whatever source derived, and provide various exclusions from gross income.

This bill, for taxable years beginning on or after January 1, 2022, and before January 1, 2027, would exclude from gross income any amount of bill credits received by a customer from a utility applicant pursuant to those acts. The bill would repeal these provisions on December 1, 2027. (6) Existing law requires any bill authorizing a new tax expenditure to contain, among other things, speciﬁc goals, purposes, and objectives that the tax expenditure will achieve, detailed performance indicators, and data collection requirements.

This bill, for speciﬁed provisions, would provide ﬁndings to comply with the additional information requirement for any bill authorizing a new tax expenditure.
(7) The bill would include ﬁndings that certain changes proposed by this bill address a matter of statewide concern rather than a municipal affair and, therefore, apply to all cities, including charter cities. (8) The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for speciﬁed reasons.
(9) This bill would appropriate $200,000,000 from the General Fund to the Energy Commission for the 2021–22 ﬁscal year to be used for a program to provide incentives for demand side grid support and associated mitigation costs, as speciﬁed.
(10) This bill would declare that it is to take effect immediately as a bill providing for appropriations related to the Budget Bill.

Appropriation: yes.
The people of the State of California do enact as follows:

SECTION 1. Article 13 (commencing with Section 16429.8) is added to Chapter 2 of Part 2 of Division 4 of Title 2 of the Government Code, to read:
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Article 13. 2022 California Arrearage Payment Program
16429.8. The Legislature ﬁnds and declares all of the following:
(a) On March 4, 2020, Governor Newsom proclaimed that a state of emergency exists in California as a result of the rise of COVID-19. (b) A nationwide emergency in response to COVID-19 was declared on March 13, 2020, pursuant to the federal Robert T. Stafford Disaster Relief and Emergency Assistance Act (42 U.S.C. Sec. 5121 et seq.). A federal major disaster declaration for California was approved on March 20, 2020, and is still in effect.
(c) Under Section 139 of the Internal Revenue Code, certain payments made by the state to individuals in connection with the COVID-19 pandemic qualify as disaster relief payments that are excluded from the recipient’s gross income.
(d) As a federal declared disaster, the COVID-19 pandemic is considered a qualiﬁed disaster for purposes of Section 139 of the Internal Revenue Code.Those payments made in the 2021–22 state ﬁscal year towards utility bills under the California Arrearage Payment Program (Article 12 (commencing with Section 16429.5)), which was established in the 2021 State Budget, were considered qualiﬁed disaster relief payments by the Internal Revenue Service and excluded from an individual’s gross income. (e) Californians continue to struggle to afford the cost of energy due to the economic impacts of the ongoing COVID-19 pandemic.
(f) Beneﬁts issued under this chapter are for past due energy utility bills accrued during the COVID-19 pandemic and the Legislature intends for them to be treated as qualiﬁed disaster relief payments that are to be excluded from individual taxable gross income pursuant to Section 139 of the Internal Revenue Code.
16429.9. For purposes of this article, the following deﬁnitions apply:
(a) “2022 CAPP” means the 2022 California Arrearage Payment Program established in Section 16429.10.
(b) “COVID-19 pandemic bill relief period” means the period starting March 4, 2020, and ending December 31, 2021, inclusive of both start and end dates.
(c) “Department” means the Department of Community Services and Development.
(d) “Electrical cooperative” has the same meaning as deﬁned in Section 2776 of the Public Utilities Code.
(e) “Electrical corporation” has the same meaning as deﬁned in Section 218 of the Public Utilities Code.
(f) “Gas corporation” has the same meaning as deﬁned in Section 222 of the Public Utilities Code.
(g) “Load-serving entity” has the same meaning as deﬁned in Section 380 of the Public Utilities Code.
(h) “Local publicly owned electric utility” has the same meaning as deﬁned in Section 224.3 of the Public Utilities Code.
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(i) “Past due bills” means active residential customer accounts with a past due balance incurred during the COVID-19 pandemic bill relief period and includes 2022 CAPP-eligible residential customer accounts that have payment plans or payment arrangements.
(j) “Program notice” means ofﬁcial guidance issued by the department regarding 2022 CAPP implementation and administration.
(k) “Utility applicant” means any of the following:
(1) A local publicly owned electric utility.
(2) An electrical corporation.
(3) A gas corporation.
(4) An electrical cooperative.
16429.10. (a) Upon appropriation, the 2022 California Arrearage Payment Program is established in the Department of Community Services and Development.
(b) The department shall release program notices and post program notices related to 2022 CAPP administration on its public-facing internet website.
(c) All active residential utility customers with past due bills incurred during the COVID-19 pandemic bill relief period are considered eligible for 2022 CAPP assistance and shall be included in a utility applicant’s request for 2022 CAPP funding.
(1) The department and utility applicants shall prioritize the issuance of 2022 CAPP assistance in the following order:
(A) Active residential customers with past due bills and who, absent the 2022 CAPP assistance or any other protection or assistance provided by the utility applicant, might be subject to service disconnection, consistent with current law, due to nonpayment of balances incurred during the COVID-19 pandemic bill relief period.
(B) Active residential customers with past due bills incurred during the COVID-19 pandemic bill relief period.
(2) The department, in its application approval and allocation notice to utility applicants, shall direct utility applicants on how 2022 CAPP assistance will be applied to each of the priority groups. A utility applicant shall be responsible for correcting any misapplication of 2022 CAPP assistance when that failure was due to a utility applicant not properly applying 2022 CAPP assistance to residential customer accounts in accordance with program notices, 2022 CAPP application terms and conditions, and guidance issued by the department.
(d) Within 90 days of receiving funds, upon appropriation, the department shall make available an online application for utility applicants to request 2022 CAPP funding for residential customers.
(1) To receive 2022 CAPP funding, a utility applicant shall complete a 2022 CAPP application, submit all necessary data and information to support the utility applicant’s 2022 CAPP application, execute the 2022 CAPP terms and conditions document, and comply with all department-issued program notices.
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(2) All utility applicant 2022 CAPP applications shall include the total number of eligible residential accounts, the total amount of eligible residential account arrearages incurred during the COVID-19 pandemic bill relief period, and identify for each eligible residential account the corresponding account number and past due bill balance accumulated during the COVID-19 pandemic bill relief period.
(3) The general manager, utility director, or a designee shall certify that the 2022 CAPP application is true and accurate and execute the 2022 CAPP terms and conditions.
(4) (A) Customer information shall be subject to Section 6254.16. This subparagraph shall become inoperative on January 1, 2023. (B) Customer information shall be subject to Section 7927.410. This subparagraph shall become operative on January 1, 2023. (e) There shall be a 30-day application timeframe in which utility applicants may apply to the department for 2022 CAPP funds. The department shall contact a utility applicant that does not respond during the initial application period to inquire as to the status of the utility applicant’s 2022 CAPP application.
(f) The department shall review utility applicant 2022 CAPP applications for completeness and conﬁrm that utility applicants’ submissions support the total amount of ﬁnancial assistance requested on behalf of residential customers. Incomplete 2022 CAPP applications shall be returned to the utility applicant for corrections or amendments consistent with department notes or directives.
(g) One billion one hundred ninety-seven million dollars ($1,197,000,000) appropriated in Item 4700-101-3398 of the Budget Act of 2022 shall be used for the 2022 CAPP program. The allocation may be adjusted for the purposes of administrative costs. Upon appropriation, the following speciﬁed amounts shall be allocated for each utility category. Funding allocation to one of the categories that is not necessary for assistance for that category maybe reallocated to another category.
(1) Two hundred thirty-nine million four hundred thousand dollars ($239,400,000) shall be allocated for ﬁnancial assistance to customers of local publicly owned electric utilities and electrical cooperatives. (2) Nine hundred ﬁfty-seven million six hundred thousand dollars ($957,600,000) shall be allocated for ﬁnancial assistance to customers of electrical corporations and gas corporations, including customers served by a community choice aggregator.
(h) To establish statewide 2022 CAPP allocations, the department shall develop an allocation formula for determining an individual utility applicant’s share of 2022 CAPP funds based on the proportional share of the total statewide energy utility arrearages.
(1) When determining statewide 2022 CAPP allocations, the department shall ensure utility applicant allocations do not exceed the total amount of eligible arrearages reported in the utility applicant’s 2022 CAPP application.

If there are remaining 2022 CAPP funds after the initial allocation determination, the department shall redistribute the remaining 2022 CAPP 95 Ch. 61—9 —
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funds to utility applicants according to their proportional share of the total statewide energy utility arrearages within each utility category. (2) Upon approving a utility applicant’s 2022 CAPP application, the department shall submit to the utility applicant an application approval and allocation notice that identiﬁes the utility applicant’s allocation along with directions on how to apply 2022 CAPP funds to customer accounts by priority group. The department shall make all application approval and allocation notices available on its public-facing internet website. (3) Utility applicants shall provide beneﬁts to residential customers in accordance with program notices, the 2022 CAPP application terms and conditions document, and guidance issued by the department. (4) The department shall approve utility applicant’s 2022 CAPP applications, set statewide allocations, and disburse funds within seven months of the appropriation for the 2022 CAPP.
(i) Within 60 days of receiving 2022 CAPP funds, a utility applicant shall issue 2022 CAPP beneﬁts to its residential customers as bill credits to help address the past due bills and shall include a statement that the credits are a result of 2022 CAPP funding or other statement as approved by a department-issued program notice.
(1) Between the time when a utility applicant submits its 2022 CAPP application and the department completes the disbursement of CAPP allocations to all utility applicants, a utility applicant shall not discontinue service due to nonpayment by those residential customers with arrearages accrued during the COVID-19 pandemic bill relief period. (2) A utility applicant shall not disconnect a residential customer’s utility service, regardless of balance owed after applying a 2022 CAPP beneﬁt, for 90 days after a 2022 CAPP beneﬁt is applied.
(3) If a residential customer has a remaining balance after a 2022 CAPP beneﬁt is applied, the utility applicant shall notify the residential customer of the option to enter into an extended payment plan with late fees and penalties waived. The utility applicant shall not discontinue service to the residential customer while the residential customer remains current on the repayment plan.
(4) Utility applicants shall waive any associated late fees and accrued interest for residential customers that are awarded 2022 CAPP beneﬁts. (5) An electrical corporation shall use existing proportional payment processes adopted by the Public Utilities Commission in response to the COVID-19 pandemic to allocate any partial payments made by residential customers to the utility applicant and other load serving entities in proportion to their respective shares of the outstanding customer charges. (j) An electrical corporation shall issue 2022 CAPP beneﬁts to residential customer for past due bills owed to the utility applicant and other load-serving entities serving the residential customer in proportion to their respective shares of customer arrearages.
(k) Within six months of a utility applicant’s receipt of its 2022 CAPP allocation, the utility applicant shall submit all reporting required by the department detailed in a program notice. The utility applicant shall remit 95 —10 — Ch. 61
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payment of any unapplied 2022 CAPP beneﬁts to the department as part of its reporting to the department.
(l) Within 60 days of receiving reporting from utility applicants pursuant to subdivision (k), the department shall provide to the Legislature, and make available on its public-facing internet website, a report. The report shall be submitted in conformance with Section 9795 and shall include all of the following:
(1) Total arrearage amount applied for statewide.
(2) Total active residential customers in arrears applied for statewide. (3) Total 2022 CAPP funds applied for by utility applicants. (4) Total 2022 CAPP funds approved by the department and disbursed to utility applicants statewide.
(5) Total 2022 CAPP funds distributed by utility applicants. (6) Total 2022 CAPP funds not expended and returned to the department by utility applicants.
(7) Total active residential customers, statewide, included in 2022 CAPP applications received by the department.
(8) Total active residential customers, by utility applicant, included in 2022 CAPP applications received by the department.
(9) Total active residential customers, statewide, that received a 2022 CAPP beneﬁt.
(10) Average 2022 CAPP beneﬁt, statewide, received by active residential customers.
(11) Total active residential customers, by utility applicant, that received a 2022 CAPP beneﬁt.
(12) Average 2022 CAPP beneﬁt, by utility applicant, received by active residential customers.
(13) Total expenditures by the department for the administration of 2022 CAPP.
(m) Utility applicants shall provide all documents and data necessary for the department, or its designee, to complete a review and audit of 2022 CAPP beneﬁts applied to eligible residential accounts. The department shall provide 30 days’ notice to utility applicants of any document requests to support departmental review and audit.
(n) Notwithstanding any other law, the payment authorized pursuant to this section shall be treated in the same manner as the federal earned income refund for the purpose of determining eligibility to receive beneﬁts under Division 9 (commencing with Section 10000) of the Welfare and Institutions Code, excluding beneﬁts under Chapter 7 (commencing with Section 14000) of Part 3 of Division 9 of the Welfare and Institutions Code, or amounts of those beneﬁts.
(o) Notwithstanding any other law, the payment authorized pursuant to this section shall not be considered as income and shall not be taken into account as resources for a period of 12 months from receipt, for purposes of determining the eligibility of the individual, or any other individual, for beneﬁts or assistance or the amount or extent of beneﬁts or assistance under any state or local program not covered in subdivision (n). With respect to 95 Ch. 61—11 —
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a state or local program, this subdivision shall only be implemented to the extent that it does not conﬂict with federal law relating to that program, and that any required federal approval or waiver is ﬁrst obtained for that program.

SEC. 2. Section 25216.8 is added to the Public Resources Code, to read:
25216.8. (a) On or before January 31, 2023, the commission, in consultation with the Public Utilities Commission, the Department of Water Resources, and California balancing authorities, including, but not limited to, the Independent System Operator, shall issue a written report to the Joint Legislative Budget Committee addressing all of the following:
(1) An evaluation of how the state, load-serving entities, as deﬁned in Section 380 of the Public Utilities Code, local publicly owned electric utilities, as deﬁned in Section 224.3 of the Public Utilities Code, and California balancing authorities managed summer reliability during 2022. (2) The magnitude of projected reliability problems in 2023 to 2026, inclusive.
(3) Potential solutions to addressing reliability concerns. In doing so, the commission shall evaluate options that rely on state budget actions, statutory changes, and using existing resource adequacy, integrated resource planning, and other reliability processes at the Public Utilities Commission and the Independent System Operator to ensure reliability.
(b) (1) A report to be submitted pursuant to subdivision (a) shall be submitted in compliance with Section 9795 of the Government Code. (2) Pursuant to Section 10231.5 of the Government Code, this section is repealed on January 1, 2027.

SEC. 3. Section 25403.2 of the Public Resources Code is amended to read:
25403.2. (a) Using the moneys appropriated pursuant to Items 3360-105-0001 and 3360-005-0001 of Section 2.00 of the Budget Act of 2021, the commission shall implement and administer a statewide program to incentivize the construction of new multifamily and single-family market-rate residential buildings as all-electric buildings or with energy storage systems. The commission shall provide a combined incentive if a building is both all electric and has an energy storage system. (b) The program implemented and administered pursuant to this section shall be known as the Building Initiative for Low-Emissions Development Program Phase 2.
(c) In implementing and administering the Building Initiative for Low-Emissions Development Program Phase 2, the commission shall do all of the following:
(1) Before June 30, 2022, develop and approve program guidelines in a public process. TheAdministrative Procedure Act (Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3 of Title 2 of the Government Code) does not apply to the development and approval of the guidelines. (2) Make program applications available within 30 days of the commission approving the guidelines pursuant to paragraph (1). (3) Ensure, to the extent reasonable, that the program incentivizes the construction of buildings as all electric or with energy storage systems that 95 —12 — Ch. 61
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would not have otherwise been constructed as all electric or with energy storage systems but for the Building Initiative for Low-Emissions Development Program Phase 2.
(4) Ensure, to the extent reasonable, that the program incentivizes the installation of technologies not otherwise required pursuant to the applicable local and state building codes.
(d) A goal of the Building Initiative for Low-Emissions Development Program Phase 2 is to spur signiﬁcant market adoption of all-electric buildings and energy storage systems.
(e) The commission may pay an incentive upfront if not doing so would inhibit participation in the Building Initiative for Low-Emissions Development Program Phase 2.

SEC. 4. Chapter 6.2 (commencing with Section 25545) is added to Division 15 of the Public Resources Code, to read:

Chapter 6.2. Certification of Nonfossil-Fueled Powerplants, Energy Storage Facilities, and Related Facilities
25545. For purposes of this chapter, the following deﬁnitions apply:
(a) “California NativeAmerican tribe” has the same meaning as set forth in Section 21073.
(b) “Facility” means any of the following:
(1) A solar photovoltaic or terrestrial wind electrical generating powerplant with a generating capacity of 50 megawatts or more and any facilities appurtenant thereto.
(2) An energy storage system as deﬁned in Section 2835 of the Public Utilities Code that is capable of storing 200 megawatthours or more of electrical energy.
(3) A stationary electrical generating powerplant using any source of thermal energy, with a generating capacity of 50 megawatts or more, excluding any powerplant that burns, uses, or relies on fossil or nuclear fuels.
(4) A discretionary project as described in Section 21080 for which the applicant has certiﬁed that a capital investment of at least two hundred ﬁfty million dollars ($250,000,000) will be made over a period of ﬁve years and the discretionary project is for (A) the manufacture, production, or assembly of an energy storage system or component manufacturing, wind system or component manufacturing, and solar photovoltaic energy system or component manufacturing, or (B) the manufacture, production, or assembly of specialized products, components, or systems that are integral to renewable energy or energy storage technologies.
(5) An electric transmission line carrying electric power from a facility described in paragraph (1), (2), or (3) that is located in the state to a point of junction with any interconnected electrical transmission system. (c) “Site” means any location on which an eligible facility is constructed or is proposed to be constructed.
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25545.1. (a) A person proposing an eligible facility may ﬁle an application no later than June 30, 2029, for certiﬁcation with the commission to certify a site and related facility in accordance with this chapter, including a person who has an application for certiﬁcation or small powerplant exemption ﬁled with the commission pursuant to Chapter 6 (commencing with Section 25500) pending as of the effective date of this section. Upon receipt of the application, the commission shall have the exclusive power to certify the site and related facility, whether the application proposes a new site and related facility or a change or addition to an existing facility.

This section does not modify the Public Utilities Commission’s jurisdiction, including the issuance of a certiﬁcate of public convenience and necessity under Chapter 5 (commencing with Section 1001) of Part 1 of Division 1 of the Public Utilities Code for a facility that is proposed by a utility regulated by the Public Utilities Commission.
(b) (1) Except as provided in paragraph (2), the issuance of a certiﬁcate by the commission for a site and related facility pursuant to this chapter shall be in lieu of any permit, certiﬁcate, or similar document required by any state, local, or regional agency, or federal agency to the extent permitted by federal law, for the use of the site and related facilities, and shall supersede any applicable statute, ordinance, or regulation of any state, local, or regional agency, or federal agency to the extent permitted by federal law. (2) Paragraph (1) does not supersede the authority of the State Lands Commission to require leases and receive lease revenues, if applicable, or the authority of the California Coastal Commission, the San Francisco Bay Conservation and Development Commission, the State Water Resources Control Board, or the applicable regional water quality control boards. (3) For facilities described in paragraph (4) of subdivision (b) of Section 25545, this subdivision does not supersede the authority of local air quality management districts or the Department of Toxic Substances Control. (c) The Legislature ﬁnds and declares that this section addresses a matter of statewide concern rather than a municipal affair as that term is used in Section 5 of Article XI of the California Constitution. Therefore, this section applies to all cities, including charter cities.
25545.2. An application for a site and related facility submitted pursuant to this chapter shall be in a form prescribed by the commission and shall contain all of the information required by Section 25520 and be further supported by other information as the commission may require to support the preparation of an environmental impact report and issuance of a certiﬁcation.
25545.3. For purposes of sections 25545.3.3 and 25545.3.5, the following deﬁnitions apply:
(a) “Construction” includes any new construction work and subsequent construction work following initial completion that is contracted out to a contractor in the construction industry.
(b) “Covered project” or “project” means a site and related facility subject to an application submitted under this chapter.
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(c) “Project labor agreement” has the same meaning as set forth in Section 2500 of the Public Contract Code.
(d) “Skilled and trained workforce” has the same meaning as provided in Chapter 2.9 (commencing with Section 2600) of Part 1 of Division 2 of the Public Contract Code.
25545.3.3. An application for a covered project submitted under this chapter shall include the applicant’s certiﬁcation that it will meet the requirements of a covered project and the commission shall make the requirements a condition of certiﬁcation. The application shall also include the applicant’s certiﬁcation that either of the following is true:
(a) The entirety of the construction of the covered project is a public work for purposes of Chapter 1 (commencing with Section 1720) of Part 7 of Division 2 of the Labor Code.
(b) The construction of the covered project is not in its entirety a public work for which prevailing wages must be paid under Article 1 (commencing with Section 1720) of Chapter 1 of Part 7 of Division 2 of the Labor Code, but all construction workers employed on the project will be paid at least the general prevailing rate of per diem wages for the type of work and geographic area, as determined by the Director of Industrial Relations pursuant to Sections 1773 and 1773.9 of the Labor Code, except that apprentices registered in programs approved by the Chief of the Division ofApprenticeship Standards may be paid at least the applicable apprentice prevailing rate. If the project is subject to this subdivision, for those portions of the project that are not a public work, all of the following shall apply:
(1) The applicant shall ensure that the prevailing wage requirement is included in all contracts for the performance of all construction work. (2) All contractors and subcontractors shall pay to all construction workers employed in the construction of the project at least the general prevailing rate of per diem wages, except that apprentices registered in programs approved by the Chief of the Division of Apprenticeship Standards may be paid at least the applicable apprentice prevailing rate. (3) All contractors and subcontractors performing construction work on the project shall employ apprentices at no less than the ratio required in Section 1777.5 of the Labor Code.
(4) Except as provided in paragraph (6), all contractors and subcontractors performing construction work shall maintain and verify payroll records pursuant to Section 1776 of the Labor Code, make those records available for inspection and copying as provided therein, and furnish those payroll records to the Labor Commissioner pursuant to Section 1771.4 of the Labor Code.
(5) Except as provided in paragraph (6), the obligation of the contractors and subcontractors to pay prevailing wages and employ apprentices may be enforced by the Labor Commissioner through the issuance of a civil wage and penalty assessment pursuant to Section 1741 of the Labor Code, which may be reviewed pursuant to Section 1742 of the Labor Code, within 18 months after the completion of the project, or by an underpaid worker through an administrative complaint or civil action, or by a joint 95 Ch. 61—15 —
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labor-management committee though a civil action under Section 1771.2 of the Labor Code. If a civil wage and penalty assessment is issued, the contractor, subcontractor, and surety on a bond or bonds issued to secure the payment of wages covered by the assessment shall be liable for liquidated damages pursuant to Section 1742.1 of the Labor Code.
(6) Paragraphs (4) and (5) do not apply if all contractors and subcontractors performing construction work on the project are subject to a project labor agreement. The project labor agreement shall also include, but not be limited to, all of the following:
(A) Provisions requiring payment of prevailing wages to all construction workers employed in the construction of the project and for enforcement of that obligation through an arbitration procedure.
(B) Targeted hiring provisions, including a targeted hiring plan, on a craft-by-craft basis to address job access for local, disadvantaged, or underrepresented workers, as deﬁned by a relevant local agency. (C) Apprenticeship utilization provisions that commit all parties to increasing the share of work performed by state-registered apprentices above the state-mandated minimum ratio required in Section 1777.5 of the Labor Code.
(D) Apprenticeship utilization provisions that commit all parties to hiring and retaining a certain percentage of state-registered apprentices that have completed the Multi-Craft Core preapprenticeship training curriculum referenced in subdivision (t) of Section 14005 of the Unemployment Insurance Code.
25545.3.5. An application for a covered project submitted under this chapter shall include the applicant’s certiﬁcation that a skilled and trained workforce will be used to perform all construction work on the project and all of the following apply:
(a) The applicant shall require in all contracts for the performance of work that every contractor and subcontractor at every tier will individually use a skilled and trained workforce to construct the project. (b) Every contractor and subcontractor shall use a skilled and trained workforce to construct the project.
(c) Except as provided in subdivision (e), contractors and subcontractors that fail to use a skilled and trained workforce shall be subject to the penalties provided in Section 2603 of the Public Contract Code. Penalties for a contractor’s or subcontractor’s failure to comply with the requirement to use a skilled and trained workforce may be assessed by the Labor Commissioner within 18 months of completion of the project using the same procedures for issuance of civil wage and penalty assessments pursuant to Section 2603 of the Public Contract Code. Penalties shall be paid to the State Public Works Enforcement Fund.
(d) For purposes of this subdivision, an applicant shall be considered to be an “awarding body” under Chapter 2.9 (commencing with Section 2600) of Part 1 of Division 2 of the Public Contract Code. Except as provided in subdivision (e), the applicant shall retain records, including copies of monthly reports, that demonstrate compliance with Chapter 2.9 (commencing 95 —16 — Ch. 61
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with Section 2600) of Part 1 of Division 2 of the Public Contract Code while the project or contract is being performed and for three years after completion of the project or contract. The applicant shall submit these records immediately upon request of the commission. When submitted to the commission, these records shall be a public record under the California Public Records Act (Chapter 3.5 (commencing with Section 6250) of Division 7 of Title 1 of the Government Code) and shall be open to public inspection.
(e) Subdivisions (c) and (d) do not apply if all contractors and subcontractors performing work on the project are subject to a project labor agreement.The project labor agreement shall also include, but not be limited to, all of the following:
(1) Provisions requiring compliance with the skilled and trained workforce requirement and for enforcement of that obligation through an arbitration procedure.
(2) Targeted hiring provisions, including a targeted hiring plan, on a craft-by-craft basis to address job access for local, disadvantaged, or underrepresented workers, as deﬁned by a local agency.
(3) Apprenticeship utilization provisions that commit all parties to increasing the share of work performed by state-registered apprentices above the state-mandated minimum ratio required in Section 1777.5 of the Labor Code.
(4) Apprenticeship utilization provisions that commit all parties to hiring and retaining a certain percentage of state-registered apprentices that have completed the Multi-Craft Core preapprenticeship training curriculum referenced in subdivision (t) of Section 14005 of the Unemployment Insurance Code.
25545.4. (a) Within 30 days of the submission of the application, the commission shall review the application and make a determination of completeness.
(b) The executive director may require the applicant to submit additional information, documents, or data determined to be reasonably necessary to prepare the environmental impact report for the application and to make a decision on the application. The executive director shall also require the applicant to submit additional information requested by trustee agencies for the purposes of supporting a decision on the application and environmental impact report. The executive director shall transmit the request for additional information within 30 days of the submission of the application. (c) An application is deemed completed as follows:
(1) Thirty days after the submission of the application, if the executive director does not require the submission of additional information pursuant to subdivision (b).
(2) Immediately upon acceptance of the additional information requested by the executive director pursuant to subdivision (b), if the executive director requires the submission of additional information pursuant to subdivision (b).
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(d) The executive director may request additional information from the applicant to address comments by public agencies on the scope and content of the information that is required to be included in an environmental impact report for certiﬁcation. The applicant shall provide to the commission the requested information within 30 days of receiving the request. (e) (1) Except as provided in paragraph (2), no later than 270 days after the application is deemed complete, or as soon as practicable thereafter, the commission shall determine whether to certify the environmental impact report and to issue a certiﬁcate for the site and related facilities pursuant to this chapter.
(2) Paragraph (1) does not apply, and the time to certify the environmental impact report or issue a certiﬁcate for the site and related facilities pursuant to this chapter may be extended if one or more of the following occurs:
(A) The commission is required to recirculate the environmental impact report pursuant to Section 15088.5 of Title 14 of the California Code of Regulations.
(B) Substantial changes are proposed in the project that may involve new signiﬁcant environmental effects or a substantial increase in the severity of previously identiﬁed signiﬁcant effects.
(C) Substantial changes occur with respect to the circumstances under which the project is undertaken that may involve new signiﬁcant environmental effects or a substantial increase in the severity of previously identiﬁed signiﬁcant effects.
(D) New information of substantial importance, which was not known and could not have been known with the exercise of reasonable diligence before the commission publishes the notice of availability pursuant to Section 25545.7.6, is submitted that may require additional analysis and consideration.
(E) The commission, in consultation with the Department of Fish and Wildlife or the State Water Resources Control Board, if applicable, determines that additional time is necessary to obtain information and conduct surveys, including due to seasonal constraints. 25545.5. (a) Within 90 days of the effective date of this chapter, the commission shall, in coordination with the Department of Fish and Wildlife, develop a plan that ensures timely and effective consultation between the commission and the Department of Fish and Wildlife with respect to any proposed commission ﬁndings and actions to authorize the take of endangered, threatened, and candidate species pursuant to the California Endangered Species Act (Chapter 1.5 (commencing with Section 2050) of Division 3 of the Fish and Game Code) or impacts to ﬁsh and wildlife resources pursuant to Section 1602 of the Fish and Game Code. The commission shall also consult with the Department of Fish and Wildlife with respect to any proposed commission ﬁndings and actions regarding potential impacts to ﬁsh, wildlife, and plant resources and the habitats upon which they depend. The plan shall include a process to ensure that all such take and impacts are consistent with Chapter 6 (commencing with Section 95 —18 — Ch. 61
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1600) of Division 2 of, and Chapter 1.5 (commencing with Section 2050) of Division 3 of, the Fish and Game Code.
(b) Within 90 days of the effective date of this chapter, the commission shall, in coordination with the State Water Resources Control Board, develop a plan that ensures timely and effective consultation between the commission and the State Water Resources Control Board and the applicable regional water quality control board with respect to any proposed commission ﬁndings and actions related to discharges of waste that could affect the quality of waters of the state. The plan shall include provisions to ensure that all discharges are consistent with all applicable provisions of Division 7 (commencing with Section 13000) of the Water Code.
(c) The commission shall, in coordination with the Department of Toxic Substances Control, develop a plan within 90 days of the effective date of this chapter that ensures timely and effective consultation between the commission and the Department of Toxic Substances Control with respect to any proposed commission ﬁndings and actions related to hazardous waste control laws.
(d) (1) For sites and related facilities located in the geographic jurisdiction of the California Coastal Commission or the San Francisco Bay Conservation and Development Commission, the commission shall consult with the applicable agency to coordinate processing and sequencing of the applications to expedite the permitting process of those agencies. In areas of the coastal zone covered by a certiﬁed local coastal program, the California Coastal Commission shall assume coastal development review authority, using the certiﬁed local coastal program as guidance. In the Suisun Marsh Secondary Management Area and the portions of the Primary ManagementArea with a local protection program, the San Francisco Bay Conservation and Development Commission shall assume permitting authority for processing and issuing marsh development permits using the local protection programs as guidance.
(2) The California Coastal Commission, the San Francisco Bay Conservation and Development Commission, the State Water Resources Control Board, the applicable regional water quality control boards, the applicable local air quality management districts, or the Department of Toxic Substances Control, as applicable, shall take ﬁnal action on the eligible facility within 90 days after the certiﬁcation by the commission of the environmental impact report for the site and related facilities, if the applicant has ﬁled a complete, ﬁnal application for a permit or waste discharge requirement, as applicable, with those agencies before the certiﬁcation of the environmental impact report.
25545.6. Notwithstanding any other law, an application submitted pursuant to this chapter shall be reviewed by commission staff.The executive director shall prepare a recommendation for the commission’s consideration at a publicly noticed meeting on whether to certify an environmental impact report and issue a certiﬁcate for the site and related facilities pursuant to this chapter.
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25545.7. (a) The commission is the lead agency for purposes of the California Environmental Quality Act (Division 13 (commencing with Section 21000)) and, except as provided in this chapter, shall prepare an environmental impact report pursuant to Division 13 (commencing with Section 21000).
(b) The regulatory program that implements this chapter is not a certiﬁed regulatory program under Section 21080.5.
(c) The commission may prepare an initial study pursuant to Section 15063 of Title 14 of the California Code of Regulations to help identify the signiﬁcant effects of an action taken pursuant to this chapter. 25454.7.2. The commission shall conduct public outreach to solicit input on an application to identify the range of actions, alternatives, mitigation measures, and signiﬁcant effects to be analyzed in depth in the environmental impact report as follows:
(a) Within three days after the application is deemed complete pursuant to Section 25545.4, the commission shall issue a notice of preparation pursuant to Section 15082 of Title 14 of the California Code of Regulations. (b) (1) No sooner than 10 days and no later than 30 days after the application is deemed complete pursuant to Section 25545.4, the commission shall conduct a public informational meeting as close as practicable to the proposed site. The commission shall provide notice of the informational meeting at least 10 days before the meeting. The notice shall be sent electronically to all persons who have requested to receive a notice from the commission on action related to certiﬁcation pursuant to this chapter and to all persons who the commission’s executive director, in consultation with the public advisor of the commission, determines to be concerned with the application. The informational meeting shall provide all of the following:
(A) Information on the proposed site and related facility from the applicant and from commission staff.
(B) Information on how to participate in the commission’s review of the application.
(C) A reasonable opportunity for the public to comment on the application.
(2) No sooner than 10 days after the application is deemed complete pursuant to Section 25545.4 and no later than 60 days after the issuance of the notice of availability pursuant to section 25545.7.6, the commission shall conduct a public workshop in the community nearest to the proposed site.The commission shall provide the notice in the same manner as required for the notice of the informational meeting pursuant to paragraph (1). (3) Not later than 30 days after the issuance of the notice of preparation, the commission shall conduct a public scoping meeting pursuant to subdivision (c) of Section 15082 of Title 14 of the California Code of Regulations as close as practicable to the proposed site. (c) The commission may conduct the informational meeting at the same time as the scoping meeting.
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immediate environment and the cultural practices that build on that knowledge, including California Native American tribes’ intimate and detailed knowledge of plants, animals, and natural phenomena, the development and use of appropriate technologies for hunting, ﬁshing, trapping, agriculture, and forestry, and a holistic knowledge or worldview that parallels the scientiﬁc discipline of ecology.
(b) Within ﬁve days after the application is deemed complete pursuant to Section 25545.4, the commission shall submit the application to all California Native American tribes that are culturally and traditionally associated with the geographic area of the proposed site and initiate consultation with those tribes pursuant to Sections 21080.3.1, 21080.3.2, and 21082.3.
(c) The commission shall take feasible measures to avoid or minimize adverse impacts to tribal cultural resources.
(d) During the consultation process, the commission shall solicit the traditional ecological knowledge of the California Native American tribes and, where feasible, incorporate the California Native American tribes’ traditional ecological knowledge into the environmental impact report for the application.
(e) Where feasible, the commission shall invite tribal historic preservation ofﬁcers of, or other cultural monitors designated by, California Native American tribes that are culturally or traditionally associated with the geographic area of the proposed site to observe and monitor activities at the site during the environmental review and certiﬁcation process. 25545.7.6. (a) No sooner than 30 days and no later than 60 days after the issuance of the notice of availability of the draft environmental impact report, the commission shall hold at least one public meeting on the draft environmental impact report as close as practicable to the proposed site. (b) Notwithstanding subdivision (a) of Section 21091, the public review and comment period for the draft environmental impact report for an application shall be at least 60 days.
(c) No sooner than 30 days after the completion of the ﬁnal environmental impact report, the commission shall consider the certiﬁcation of the environmental impact report of the application at a public meeting. (d) This chapter does not limit the commission from holding additional public meetings.
25545.8. (a) For the consideration of an application and the issuance of a certiﬁcation under this chapter, the commission shall comply with the requirements of subdivisions (a), (d), (e), (g), and (h), inclusive, of Section 25523.
(b) Subdivisions (f), (g), (j) and (k) of Section 25519, and Sections 25525, 25527, and 25538 apply to an application submitted pursuant to this chapter. 25545.9. The commission shall not certify a site and related facility under this chapter unless the commission ﬁnds that the construction or operation of the facility will have an overall net positive economic beneﬁt to the local government that would have had permitting authority over the 95 Ch. 61—21 —
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site and related facility. For purposes of this section, economic beneﬁts may include, but are not limited to, any of the following:
(a) Employment growth.
(b) Housing development.
(c) Infrastructure and environmental improvements.
(d) Assistance to public schools and education.
(e) Assistance to public safety agencies and departments. (f) Property taxes and sales and use tax revenues.
25545.10. (a) The commission shall not certify a site and related facility under this chapter unless the commission ﬁnds that the applicant has entered into one or more legally binding and enforceable agreements with, or that beneﬁt, a coalition of one or more community-based organizations, such as workforce development and training organizations, labor unions, social justice advocates, local governmental entities, California Native American tribes, or other organizations that represent community interests, where there is mutual beneﬁt to the parties to the agreement. The topics and speciﬁc terms in the community beneﬁts agreements may vary and may include workforce development, job quality, and job access provisions that include, but are not limited to, any of the following:
(1) Terms of employment, such as wages and beneﬁts, employment status, workplace health and safety, scheduling, and career advancement opportunities.
(2) Worker recruitment, screening, and hiring strategies and practices, targeted hiring planning and execution, investment in workforce training and education, and worker voice and representation in decisionmaking affecting employment and training.
(3) Establishing a high road training partnership, as deﬁned in Section 14005 of the Unemployment Insurance Code.
(b) The topics and speciﬁc terms in the community beneﬁts agreement may also include, but not be limited to, funding for or providing speciﬁc community improvements or amenities such as park and playground equipment, urban greening, enhanced safety crossings, paving roads and bike paths, and annual contributions to a nonproﬁt or community-based organization that awards grants to organizations delivering community-based services and amenities.
25545.11. Sections 25532 to 25534.2, inclusive, apply to a certiﬁcation issued pursuant to this chapter.
25545.12. (a) Regulations adopted to implement this chapter, or any amendment to those regulations, shall be adopted by the commission in accordance with Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3 of Title 2 of the Government Code. The adoption of these regulations shall be considered by the Ofﬁce of Administrative Law as an emergency, and necessary for the immediate preservation of the public peace, health, safety, and general welfare. Notwithstanding any other of law, the emergency regulations adopted to implement this chapter shall remain in effect until amended by the commission.
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(b) (1) Notwithstanding any other law, until July 1, 2025, an agreement entered into for purposes of this chapter shall not require competitive bidding, or the review, consent, or approval of the Department of General Services or any other state department or agency and is not required to comply with the requirements of the State Contracting Manual, the Public Contract Code, or the personal services contracting requirements of Article 4 (commencing with Section 19130) of Chapter 5 of Part 2 of Division 5 of Title 2 of the Government Code.
(2) If the commission enters into an agreement with a local government pursuant to this subdivision, the commission may advance funds to the local government for purposes of the agreement.
25545.13. (a) A site and related facility certiﬁed under this chapter is deemed an environmental leadership development project certiﬁed by the Governor under Chapter 6.5 (commencing with Section 21178) of Division 13 and eligible for the procedures established under Section 21185, with no further action by the applicant or the Governor, if the commission veriﬁes that the conditions in Chapter 6.5 (commencing with Section 21178) of Division 13, including Sections 21183 and 21183.6, are met and prepares the record of the proceedings concurrently with its review of the application and certiﬁes the record of proceedings within ﬁve days of certiﬁcation. (b) On and after January 1, 2026, if Chapter 6.5 (commencing with Section 21178) of Division 13 is inoperative or repealed, the procedures established pursuant to subdivision (c) shall apply to any action or proceeding brought to attack, review, set aside, void, or annul the certiﬁcation of an environmental impact report or the issuance of the certiﬁcation for any site and related facility subject to this chapter, if the commission prepares the administrative record of the proceedings concurrently with its review of the application and certiﬁes the administrative record within ﬁve days of certiﬁcation.
(c) On or before December 31, 2023, the Judicial Council shall adopt a rule of court to establish procedures that require actions or proceedings brought to attack, review, set aside, void, or annul the certiﬁcation of an environmental impact report or the issuance of the certiﬁcation for any site and related facility subject to this chapter, including any potential appeals to the court of appeal or the Supreme Court, to be resolved, to the extent feasible, within 270 days of the ﬁling of the certiﬁed administrative record with the court.

SEC. 5. Chapter 7.4 (commencing with Section 25640) is added to Division 15 of the Public Resources Code, to read:

Chapter 7.4. Long-Duration Energy Storage Program
25640. For purposes of this chapter, the following deﬁnitions apply:
(a) “Energy storage system” has the same meaning as deﬁned in Section 2835 of the Public Utilities Code.
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(b) “Financial incentive” includes a contract, grant, loan, rebate, block grant, or other appropriate funding mechanism.
(c) “Under-resourced community” has the same meaning as deﬁned in Section 71130.
25641. The commission shall establish and implement the Long-Duration Energy Storage Program to provide ﬁnancial incentives for eligible projects, located at eligible storage facilities, that have power ratings of at least one megawatt and are capable of reaching a target of at least eight hours of continuous discharge of electricity at that power rating in order to deploy innovative energy storage systems to the electrical grid for purposes of providing critical capacity and grid services.
25642. (a) The commission may establish project and storage facility eligibility guidelines for purposes of this chapter.
(b) Any eligibility guidelines established pursuant to subdivision (a) shall be consistent with both of the following requirements:
(1) “Eligible storage facility” shall include, but not be limited to, an energy storage system that is interconnected to the electrical grid in California or to a California balancing authority.
(2) (A) “Eligible project” shall include, but not be limited to, an eligible storage facility that includes any of the following:
(i) Compressed air or liquid air technologies.
(ii) Flow batteries, advanced chemistry batteries, or mechanical energy storage.
(iii) Thermal storage or aqueous battery systems.
(iv) A hydrogen demonstration project.
(B) “Eligible project” shall not include a pumped storage project or lithium-ion-based storage technology.
25643. In implementing the Long-Duration Energy Storage Program, the commission may do all of the following:
(a) In addition to any other authorized method of providing moneys to participants in the Long-Duration Energy Storage Program, use ﬁnancial incentives.
(b) Award Long-Duration Energy Storage Program moneys for technical assistance, including, but not limited to, providing outreach to eligible industries, identifying promising technologies, assessing market conditions needed to accelerate commercial traction of the technology, assisting with technical review of proposals and deliverables, identifying opportunities that provide signiﬁcant beneﬁts to the electrical grid, and performing beneﬁts analysis. The commission may contract for, or through interagency agreement obtain, technical, scientiﬁc, and administrative services and expertise from one or more entities to support the Long-Duration Energy Storage Program.
(c) Adopt guidelines or other standards at a business meeting for the Long-Duration Energy Storage Program. The Administrative Procedure Act (Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3 of Title 2 of the Government Code) does not apply to the adoption of the 95 —24 — Ch. 61
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guidelines or other standards adopted by the commission pursuant to this chapter.
(d) (1) Notwithstanding any other law, noncompetitively award Long-Duration Energy Storage Program moneys through an amendment to, or a new agreement with a party to or recipient of, contracts or grants from California governmental entities or a federal agency if the recipient has received funding for the original project through a competitive bid process from a California governmental entity or federal agency and the awarding of those moneys is consistent with the stated goals and criteria of the Long-Duration Energy Storage Program.
(2) Notwithstanding any other law, noncompetitively award Long-Duration Energy Storage Program moneys to a governmental entity, national laboratory, entity contracted by the federal government to operate a national laboratory, or foundation established to serve the University of California or California State University.
(3) Notwithstanding any other law, noncompetitively award Long-Duration Energy Storage Program moneys to any entity if the cost to the state is reasonable and the commission makes any of the following determinations:
(A) The expertise, service, or product is unique.
(B) A competitive solicitation would frustrate the obtainment of necessary information, goods, or services in a timely manner.
(C) The moneys to be awarded would fund the next phase of a multiphased project, the multiphased project was funded through competitively awarded agreement, and the entity satisfactorily performed the competitively awarded agreement.
(D) It is in the best interests of the state to do so. (E) The entity will use the moneys as matching funds for federally awarded moneys.
(e) Notwithstanding any other law, in its discretion, advance up to 25 percent of the Long-Duration Energy Storage Program moneys awarded pursuant to this chapter.
25644. Notwithstanding any other law, a commission agreement entered into for purposes of the Long-Duration Energy Storage Program shall not require the review, consent, or approval of the Department of General Services or any other state department or agency and are not required to comply with the requirements of the State Contracting Manual, the Public Contract Code, or the personal services contracting requirements of Article 4 (commencing with Section 19130) of Chapter 5 of Part 2 of Division 5 of Title 2 of the Government Code.
25645. In providing ﬁnancial incentives pursuant to this chapter, the commission shall give preference to an eligible project that does one or more of the following:
(a) Increases the reliability and resiliency of the electrical grid. (b) Adds electrical grid services when the electrical grid is stressed or anticipating pending energy challenges.
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(c) Increases the use of renewable energy and reduces the impact of climate change on the electrical grid or on connected facilities or communities, including by improving air quality, reducing emissions of greenhouse gases, or providing under-resourced communities with increased reliability and resiliency.
(d) Lowers energy costs and provides employment opportunities for residents of under-resourced communities.
(e) Interconnects to the electrical grid and is commercially operational by 2028.

SEC. 6. Chapter 8.9 (commencing with Section 25790) is added to Division 15 of the Public Resources Code, to read:

Chapter 8.9. Strategic Reliability Reserve
Article 1. General Provisions and Deﬁnitions
25790. The Legislature ﬁnds and declares all of the following:
(a) California is a leader in driving the affordable and equitable transition to a clean reliable energy system and economy. However, the impacts of climate change are occurring sooner and with more intensity and frequency than previously anticipated.
(b) Extreme events from climate change, including heat waves, wildﬁres, and drought, combined with other factors, such as supply chain disruptions, are jeopardizing California’s ability to build out the electrical infrastructure needed to maintain affordability and reliability.
(c) As California transitions to a clean energy future and contends with climate impacts and other challenges, sufﬁcient capacity of new and existing generation assets will be required to maintain reliability during extreme events.
(d) California must ensure electricity reliability during this period of heightened risk, which includes extraordinary near-term measures and substantive changes to mid-term energy policy, while also ensuring the multifaceted California electrical grid is best positioned to sustainably and equitably achieve California’s clean energy future, climate targets, and air quality requirements.
25790.5. For purposes of this chapter, the following deﬁnitions apply:
(a) “California balancing authority” has the same meaning set forth in Section 399.12 of the Public Utilities Code.
(b) “Extreme event” means either of the following:
(1) An event occurring at a time and place in which weather, climate, or environmental conditions, including temperature, precipitation, drought, ﬁre, or ﬂooding, present a level of risk that would constitute or exceed a one-in-ten event, as referred to by the North American Electric Reliability Corporation, including when forecast in advance by a load-serving entity or local publicly owned electric utility.
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(2) An event where emergency measures are taken by a California balancing authority, including when forecast in advance by the California balancing authority.
(c) “Fund” means the Strategic Reliability Reserve Fund established pursuant to Section 25793.
(d) “Load-serving entity” has the same meaning as deﬁned in Section 380 of the Public Utilities Code.
(e) “Local publicly owned electric utility” has the same meaning as deﬁned in Section 224.3 of the Public Utilities Code.
(f) “State board” means the State Air Resources Board.

Article 2. Distributed Electricity Backup Assets Program 25791. (a) The Distributed Electricity Backup Assets Program is hereby created. The commission shall implement and administer the program to incentivize the construction of cleaner and more efﬁcient distributed energy assets that would serve as on-call emergency supply or load reduction for the state’s electrical grid during extreme events.
(b) In implementing and administering the program, the commission, in coordination with the state board, shall allocate moneys for either of the following:
(1) Efﬁciency upgrades, maintenance, and capacity additions to existing power generators, consistent with subdivision (e).
(2) Deployment of new zero- or low-emission technologies, including, but not limited to, fuel cells or energy storage, at existing or new facilities. (c) The commission shall develop guidelines, in consultation with the state board, to implement the program. The guidelines shall include a loading order that aims to achieve electricity reliability and prioritizes feasible, cost-effective demand response and efﬁciency resources, then feasible, cost-effective renewable and zero-emission resources, and then feasible, cost-effective conventional resources. The guidelines shall also consider the anticipated useful life of the resources in relation to the state’s climate and air quality requirements.
(d) The state board, in consultation with air pollution control districts and air quality management districts, as appropriate, shall identify the cleanest available technologies and equipment that would qualify for the incentives for backup generators under the guidelines, inclusive of the emissions of greenhouse gases, criteria air pollutants, and toxic emissions associated with obtaining and using feedstock fuels.
(e) The commission, in consultation with the state board, may fund new efﬁciency upgrades, maintenance, and incremental capacity additions to existing power generators. As a condition of the receipt of funds for this purpose, as applicable, generator operators shall comply with regulations adopted pursuant to Part 2 (commencing with Section 38530) of, and Part 5 (commencing with Section 38570) of, the California Global Warming SolutionsAct of 2006 (Division 25.5 (commencing with Section 38500) of 95 Ch. 61—27 —
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the Health and Safety Code), including, but not limited to, the mandatory reporting of emissions of greenhouse gasses and market-based compliance mechanism.
(f) All funding recipients under the program shall participate as an on-call emergency resource for the state during extreme events. 25791.5. The commission shall transfer moneys from the Distributed Electricity Backup Assets Account to the state board to be used in the Climate Heat Impact Response Program established pursuant to the proclamation of a state of emergency issued by Governor Gavin Newsom on July 31, 2021.

Article 3. Demand Side Grid Support Program
25792. (a) The Demand Side Grid Support Program is hereby created.

The commission shall implement and administer the program to incentivize dispatchable customer load reduction and backup generation operation as on-call emergency supply and load reduction for the state’s electrical grid during extreme events.
(b) The commission shall allocate moneys to develop a new statewide program that provides incentives to reduce customer net load during extreme events with upfront capacity commitments and for per-unit reductions in net load. Eligible recipients shall include all energy customers in the state, except those that are eligible to participate in demand response or emergency load reduction programs offered by entities under the jurisdiction of the Public Utilities Commission. Payments shall be made to any of the following:
(1) Participating individual entities.
(2) Participating aggregators of multiple energy customers. (3) Participating local publicly owned electric utilities and load-serving entities.
(c) Entities with generation or load reduction assets that are incentivized pursuant to Article 2 (commencing with Section 25791) shall participate in the program under this article.
(d) Participants shall provide load reduction or backup generation service, or both, in response to a dispatch by an applicable California balancing authority of a California balancing authority area in which participants are located during extreme events.
(e) The commission, in consultation with California balancing authorities and the state board, shall adopt guidelines to determine when to implement the program, including which resources are dispatched ﬁrst to minimize local pollution and emissions of greenhouse gases. The dispatch order of resources in the program shall follow a loading order that prioritizes, to the maximum extent feasible to ensure electricity reliability, cost-effective demand response and efﬁciency resources, then feasible, cost-effective renewable and zero-emission resources, and then feasible, cost-effective conventional resources. The guidelines shall also consider the anticipated 95 —28 — Ch. 61
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useful life of the resources in relation to the state’s climate and air quality requirements.
(f) The state board, in consultation with the commission, shall develop a plan, including determining the funding amounts allocated after the dispatch of resources participating in the program, to mitigate impacts from these resources.
(g) All energy produced as a result of the program shall be settled at a relevant reference energy price derived either through the Independent System Operator market tariff or similar mechanism established and documented for an applicable California balancing authority area.

Article 4. Strategic Reliability Reserve Fund
25793. (a) The Strategic Reliability Reserve Fund is hereby created in the State Treasury. Notwithstanding Section 13340 of the Government Code, the moneys in the fund and the accounts contained in the fund are hereby continuously appropriated without regard to ﬁscal year to be expended by the commission for purposes of adding resources to the electrical grid to ensure electrical grid reliability and support the clean energy transition. (b) The Distributed Electricity Backup AssetsAccount is hereby created in the fund, to be administered by the commission to implement the Distributed Electricity Backup Assets Program in accordance with Article 2 (commencing with Section 25791).
(c) The Demand Side Grid Support Account is hereby created in the fund, to be administered by the commission to implement the Demand Side Grid Support Program in accordance with Article 3 (commencing with Section 25792). Revenue generated by the sale of energy services within the Demand Side Grid Support Program shall be deposited into the Demand Side Grid Support Account.
(d) The commission may accept nonstate moneys, including, but not limited to, federal moneys, for purposes of this chapter. (e) The commission shall adopt emergency regulations to implement this chapter at a commission business meeting. Notwithstanding Sections 11346.1 and 11349.6 of the Government Code, a ﬁnding of emergency or necessity to address an emergency shall not be required. Notwithstanding any other law, these emergency regulations shall be valid for three years, or until replaced by nonemergency regulations, whichever is sooner. (f) The executive director, or a designee, of the commission may approve any contract, grant, or loan entered into for purposes of this chapter until October 31, 2023. After October 31, 2023, any contract, grant, or loan entered into for purposes of this chapter shall be approved in a commission meeting held consistent with Chapter 3 (commencing with Section 25200) of Division 15. For any contract, grant, or loan entered into for purposes of this chapter, no later than 10 days after the commission, executive director, or their designee, approves the contract, grant, or loan, the executive director 95 Ch. 61—29 —
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of the commission shall give written notice to the Joint Legislative Budget Committee of the action.
(g) (1) Notwithstanding any other law, a contract, grant, or loan entered into for purposes of this chapter for an activity that is needed for ensuring electrical grid reliability by October 31, 2023, shall not require competitive bidding, or the review, consent, or approval of the Department of General Services or any other state department or agency and is not required to comply with the requirements of the State Contracting Manual, the Public Contract Code, or the personal services contracting requirements of Article 4 (commencing with Section 19130) of Chapter 5 of Part 2 of Division 5 of Title 2 of the Government Code.
(2) This subdivision does not apply to any contract, grant, or loan entered into for purposes of this chapter that is not needed for ensuring electrical grid reliability by October 31, 2023.
(3) This subdivision is inoperative on November 1, 2023. (h) Notwithstanding any other law, the commission may pay an incentive up front if not doing so would inhibit participation in the programs established pursuant to this chapter.

Article 5. Certiﬁcation of Facilities
25794. For purposes of this article, the following deﬁnitions apply:
(a) “Department” means the Department of Water Resources or a person designated by the Department of Water Resources for purposes of this article.
(b) “Facility” means a facility described in Section 80710 of the Water Code.
(c) “Site” means a location on which a facility is constructed or is proposed to be constructed.
25794.1. (a) Notwithstanding any other law, from October 31, 2022, to October 31, 2026, inclusive, the department shall submit an application for certiﬁcation to the commission in accordance with this article for a site on which a facility described in Section 80710 of the Water Code is located. (b) The issuance of a certiﬁcate by the commission for a site and related facility pursuant to this article shall be in lieu of any permit, certiﬁcate, or similar document required by any state, local or regional agency, or federal agency to the extent permitted by federal law, for the use of the site and related facility, and shall supersede any applicable statutes, including the California Coastal Act of 1976 (Division 20 (commencing with Section 30000) of this code) and Title 7.2 (commencing with Section 66600) of the Government Code, ordinances, regulations, or standards of a state, local, or regional agency, or a federal agency, to the extent permitted by federal law, and shall not be subject to the requirements of the California Environmental Quality Act (Division 13 (commencing with Section 21000)) and regulations adopted pursuant to that division.
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(c) The Legislature ﬁnds and declares that this section addresses a matter of statewide concern rather than a municipal affair as that term is used in Section 5 of Article XI of the California Constitution. Therefore, this section applies to all cities, including charter cities.
25794.2. (a) The commission shall establish a process to expedite review of an application submitted pursuant to this article. The process shall include guidance to the department on determining optimal locations for facilities based on the potential to improve reliability, reduce the occurrence of public safety power shutoffs, decrease the use of high-emission backup power, minimize air pollution, and avoid impacts on disadvantaged communities, as identiﬁed pursuant to Section 39711 of the Health and Safety Code. (b) An application submitted pursuant to this article shall be in the form prescribed by the commission and shall contain all of the information required by Section 25520 and be further supported by other information as the commission may require to enable review of the site and related facilities, and issuance of a certiﬁcation, including, at a minimum, all of the following:
(1) A description of the facility, including a showing that it is capable of delivering energy during net peak hours in response to a dispatch by the Independent System Operator during extreme events, and has access to the infrastructure and resources needed to operate.
(2) A description of the site, including whether the site is disturbed and the site’s zoning designation and the allowable uses within the zoning designation.
(3) A list of all properties and property owners within 1,000 feet of the site.
(4) A description of the potential impacts of the project on the environment and on public health and safety, including on the surrounding community, and project design measures proposed to mitigate those potential impacts. The description shall include the applicable local air district’s attainment status under the federal Clean Air Act (42 U.S.C. Sec. 7401 et seq.).
(5) A description of all local, state, regional, and federal laws, ordinances, regulations, and standards that would otherwise apply to the facility in the absence of the commission’s exclusive jurisdiction pursuant to subdivision (b) of Section 25794.1, and an analysis of the project’s compliance with those local, state, regional, and federal laws, ordinances, regulations, and standards.
(c) An application submitted pursuant to this section shall be reviewed by commission staff.The executive director shall prepare a recommendation for the commission’s consideration on whether to issue a certiﬁcate for a site and facility pursuant to this article.
25794.3. Upon receipt of an application pursuant to this article, commission staff shall establish a docket for the proceeding and publish a notice of receipt and shall mail the notice to all property owners within 1,000 feet of the proposed site. The notice shall also be sent to all local, state, and regional agencies that would have had jurisdiction over the site 95 Ch. 61—31 —
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in the absence of the commission’s exclusive jurisdiction under subdivision (b) of Section 25794.1, federal agencies with jurisdiction over the project, and any California NativeAmerican tribe that is traditionally and culturally afﬁliated with the geographic area of the proposed site. 25794.4. (a) Within 20 days of the submission of the application pursuant to this article, the executive director shall review the application for completeness. The executive director may require the department to submit additional information, documents, or data reasonably necessary to make a decision on the application. The executive director shall transmit the request for additional information within 20 days of the submission of the application.
(b) An application is deemed complete as follows:
(1) Twenty days after the submission of the application, if the executive director does not require the submission of additional information, documents, or data pursuant to subdivision (a).
(2) Immediately upon acceptance of the additional information, documents, or data requested by the executive director pursuant to subdivision (a).
(c) No later than 180 days after the application is deemed complete, or at any later time as is mutually agreed to by the commission and the department, the commission shall determine whether to issue a certiﬁcate for the site and related facility pursuant to this article. 25794.5. Upon an application being deemed complete, the commission shall do all of the following:
(a) (1) Comply with subdivisions (d) to (g), inclusive, of, and subdivision (k) of, Section 25519.
(2) Notwithstanding subdivision (f) of Section 25519, local agencies may review an application submitted by the commission under paragraph (1) and may submit comments on, among other things, the design of the facility, architectural and aesthetic features of the facility, access to highways, landscaping and grading, public use of lands in the area of the facility, proximity to sensitive receptors and other incompatible land uses, and other appropriate aspects of the design, construction, or operation of the proposed site and related facility.
(b) Provide the application to all California NativeAmerican tribes that are culturally and traditionally associated with the geographic area of the site and initiate consultation with those tribes in a manner consistent with Sections 21080.3.1 and 21080.3.2.
(c) (1) If the commission does not receive a California NativeAmerican tribe’s request for consultation pursuant to subdivision (b), the commission, within 60 days after the application has been deemed complete, shall complete a preliminary analysis for the facility’s potential impacts to environment and public health and safety and the facility’s compliance with applicable laws, ordinances, regulations, and standards that would have applied in absence of the commission’s exclusive jurisdiction under subdivision (b) of Section 25794.1.
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(2) If the commission receives a California Native American tribe’s request for consultation pursuant to subdivision (b), the commission shall complete a preliminary analysis within 30 days after the commission concludes the consultation process with the California Native American tribe pursuant to subdivision (b).
(d) Consult with local jurisdictions and state agencies in conducting the analysis and attempt to resolve any potential noncompliance with applicable laws, ordinances, regulations, and standards.
(e) Propose conditions and veriﬁcation and monitoring requirements for certiﬁcation, as appropriate, to mitigate any potential impacts to the extent feasible.
(f) Require the department to fully mitigate all air emissions in the surrounding community. The department may use the Climate Heat Impact Response Program (CHIRP) administered by the state board for compliance with this subdivision.
(g) Publish the preliminary analysis for a minimum of 30 days before a 30-day public and agency comment period.
(h) Prepare a ﬁnal analysis responding to public and agency comments and making any changes at least 10 days before the commission considers whether to approve certiﬁcation of the site and related facility. 25794.6. The commission shall not certify a site and related facility if any of the following applies:
(a) The site is a site described in Section 25527 unless the commission ﬁnds that the use is not inconsistent with the primary uses of those lands and that there will be no substantial adverse environmental impact. (b) The site has not been previously disturbed.
(c) The site does not have access to the infrastructure and resources with the necessary existing capacity and in the proximity needed to operate the facility, including, but not limited to, a natural gas line and a water line, as applicable.
(d) After July 31, 2023, the facility will use diesel fuel. 25794.7. The commission shall maintain on its internet website a list of all certiﬁcations granted pursuant to this article for as long as the certiﬁcations are in effect.
25794.8. (a) A certiﬁcate issued pursuant to this article shall be valid for a period not to exceed ﬁve years from the date of issuance. (b) If a facility operates longer than the period speciﬁed in subdivision (a), all necessary permits, certiﬁcates, or similar documents required by state, local, and federal governments shall ﬁrst be obtained. 25794.9. Sections 25532 to 25537, inclusive, apply to a certiﬁcate issued pursuant to this article.
25794.10. (a) The executive director shall charge and collect a reasonable fee from the department upon the submittal of an application pursuant to this article to cover the estimated actual cost of reviewing an application.The department shall submit a deposit along with the application that does not exceed 3 percent of the estimated capital cost of the proposed facility.
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(b) The commission staff shall separately account for the deposit collected and the charges incurred in the review of the application. The status of the account shall be provided to the department at regular intervals established by mutual agreement. The executive director shall request additional deposits if the initial deposit has been exhausted.
(c) A ﬁnal accounting shall be rendered by the commission staff after the commission has reached a ﬁnal decision on the application. If, in the ﬁnal accounting, the deposits exceed the actual costs incurred by the commission, the excess shall be refunded. If the actual costs exceed the amount of the deposits, the department shall be billed for the difference. (d) The executive director may adjust or waive deposits for minor projects. For facilities with an estimated capital cost that exceeds one million dollars ($1,000,000), the executive director shall permit payment of the deposit in increments, as determined by the executive director.

Article 6. Miscellaneous
25795. Beginning on January 31, 2023, and on May 1, August 1, and December 1 annually thereafter, the department shall issue a written report to the Joint Legislative Budget Committee detailing the actions undertaken by the department in the period since the previous report pursuant to this chapter through that date, including, but not limited to, all of the following:
(a) Amount of funds expended.
(b) Purpose of funds expended.
(c) Status of actions funded.
(d) For new and expanded resources, the amount by megawatt, resource type, operational date, and expected lifetime of that capacity. (e) The frequency at which resources funded by the department have been used and the extent to which they complied with the requirements of this chapter.
(f) In consultation with the state board, an estimate or the best available information on the emissions of greenhouse gases, criteria air pollutants, and toxic air contaminants emitted by the resources funded by the department over the period since the previous report.
(g) Summary of contracts, grants, and loans issued pursuant to this chapter.
25795.5. The provisions of this chapter are severable. If any provision of this chapter or its application is held invalid, that invalidity shall not affect other provisions or applications that can be given effect without the invalid provision or application.

SEC. 7. Section 25806 of the Public Resources Code is amended to read:
25806. (a) A person who submits to the commission an application for certiﬁcation under Chapter 6 (commencing with Section 25500) or Chapter

6.2 (commencing with Section 25545) shall submit with the application a fee of two hundred ﬁfty thousand dollars ($250,000) plus ﬁve hundred dollars ($500) per megawatt of gross generating capacity or per 95 —34 — Ch. 61
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megawatthour of gross energy storage capacity, as applicable, or seventy cents ($0.70) per square foot for a facility described in paragraph (3) of subdivision (b) of Section 25545, of the proposed facility. The total fee accompanying an application shall not exceed seven hundred ﬁfty thousand dollars ($750,000).
(b) A person who receives certiﬁcation of a site and related facility pursuant to Chapter 6 (commencing with Section 25500) or Chapter 6.2 (commencing with Section 25545) shall pay an annual fee of twenty-ﬁve thousand dollars ($25,000). For a facility certiﬁed on or after January 1, 2004, the ﬁrst payment of the annual fee is due on the date the commission adopts the ﬁnal decision. All subsequent payments are due by July 1 of each year in which the facility retains its certiﬁcation. The ﬁscal year for the annual fee is July 1 to June 30, inclusive.
(c) The fees in subdivisions (a), (b), and (e) shall be adjusted annually to reﬂect the percentage change in the Implicit Price Deﬂator for State and Local Government Purchases of Goods and Services, as published by the United States Department of Commerce.
(d) The Energy Facility License and Compliance Fund is hereby created in the State Treasury. All fees received by the commission pursuant to this section shall be remitted to the Treasurer for deposit in the fund. The money in the fund shall be expended, upon appropriation by the Legislature, for processing applications for certiﬁcation and for compliance monitoring. (e) A person who submits to the commission a petition to amend an existing project that previously received certiﬁcation shall submit with the petition a fee of ﬁve thousand dollars ($5,000). The commission shall conduct a full accounting of the actual cost of processing the petition to amend, for which the project owner shall reimburse the commission if the costs exceed ﬁve thousand dollars ($5,000). The total reimbursement and fees owed by a project owner for each petition to amend shall not exceed the amount of the maximum total ﬁling fee for an application for certiﬁcation as speciﬁed in subdivision (a) of seven hundred ﬁfty thousand dollars ($750,000), adjusted annually pursuant to subdivision (c). Any reimbursement and fees received by the commission pursuant to this subdivision shall be deposited in the Energy Facility License and Compliance Fund. This subdivision does not apply to a change in ownership or operational control of a project.

SEC. 8. Section 381 of the Public Utilities Code is amended to read:
381. (a) To ensure that the funding for the programs described in subdivision (b) and Section 382 are not commingled with other revenues, the commission shall require each electrical corporation to identify a separate rate component to collect the revenues used to fund these programs. The rate component shall be a nonbypassable element of the local distribution service.
(b) The commission shall allocate funds collected pursuant to subdivision (a), and any interest earned on collected funds, to programs that enhance system reliability and provide in-state beneﬁts as follows:
(1) Cost-effective energy efﬁciency and conservation activities. 95 Ch. 61—35 —
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(2) Public interest research and development not adequately provided by competitive and regulated markets.
(3) In-state operation and development of existing and new and emerging eligible renewable energy resources, as deﬁned in Section 399.12. (c) The commission shall order the respective electrical corporations to collect and spend these funds at the levels and for the purposes required in Section 399.8.
(d) Each electrical corporation shall allow customers to make voluntary contributions through their utility bill payments as either a ﬁxed amount or a variable amount to support programs established pursuant to paragraph (3) of subdivision (b). Funds collected by electrical corporations for these purposes shall be forwarded in a timely manner to the appropriate fund as speciﬁed by the commission.

SEC. 9. Section 739.1 of the Public Utilities Code is amended to read:
739.1. (a) The commission shall continue a program of assistance to low-income electric and gas customers with annual household incomes that are no greater than 200 percent of the federal poverty guideline levels, the cost of which shall not be borne solely by any single class of customer. For one-person households, program eligibility shall be based on two-person household guideline levels.The program shall be referred to as the California Alternate Rates for Energy or CARE program. The commission shall ensure that the level of discount for low-income electric and gas customers correctly reﬂects the level of need.
(b) The commission shall establish rates for CARE program participants, subject to both of the following:
(1) That the commission ensure that low-income ratepayers are not jeopardized or overburdened by monthly energy expenditures, pursuant to subdivision (b) of Section 382.
(2) That the level of the discount for low-income electricity and gas ratepayers correctly reﬂects the level of need as determined by the needs assessment conducted pursuant to subdivision (d) of Section 382. (c) In establishing CARE discounts for an electrical corporation with 100,000 or more customer accounts in California, the commission shall ensure all of the following:
(1) The average effective CARE discount shall not be less than 30 percent or more than 35 percent of the revenues that would have been produced for the same billed usage by non-CARE customers. The average effective discount determined by the commission shall not reﬂect any charges for which CARE customers are exempted, discounts to ﬁxed charges or other rates paid by non-CARE customers, or bill savings resulting from participation in other programs, including the medical baseline allowance pursuant to subdivision (c) of Section 739. The average effective CARE discount shall be calculated as a weighted average of the CARE discounts provided to individual customers.
(2) If an electrical corporation provides an average effective CARE discount in excess of the maximum percentage speciﬁed in paragraph (1), the electrical corporation shall not reduce, on an annual basis, the average 95 —36 — Ch. 61
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effective CARE discount by more than a reasonable percentage decrease below the discount in effect on January 1, 2013, or that the electrical corporation had been authorized to place in effect by that date. (3) The entire discount shall be provided in the form of a reduction in the overall bill for the eligible CARE customer.
(d) The commission shall work with electrical and gas corporations to establish penetration goals. The commission shall authorize recovery of all administrative costs associated with the implementation of the CARE program that the commission determines to be reasonable, through a balancing account mechanism. Administrative costs shall include, but are not limited to, outreach, marketing, regulatory compliance, certiﬁcation and veriﬁcation, billing, measurement and evaluation, and capital improvements and upgrades to communications and processing equipment. (e) The commission shall examine methods to improve CARE enrollment and participation. This examination shall include, but need not be limited to, comparing information from CARE and the Universal Lifeline Telephone Service (ULTS) to determine the most effective means of using that information to increase CARE enrollment, automatic enrollment of ULTS customers who are eligible for the CARE program, customer privacy issues, and alternative mechanisms for outreach to potential enrollees. The commission shall ensure that a customer consents before enrollment. The commission shall consult with interested parties, including ULTS providers, to develop the best methods of informing ULTS customers about other available low-income programs and the best mechanism for telephone providers to recover reasonable costs incurred pursuant to this section. (f) (1) The commission shall improve the CARE application process by cooperating with other entities and representatives of California government, including the California Health and Human Services Agency and the Secretary of California Health and Human Services, to ensure that all gas and electric customers eligible for public assistance programs in California that reside within the service territory of an electrical corporation or gas corporation, are enrolled in the CARE program. The commission may determine that gas and electric customers are categorically eligible for CARE assistance if they are enrolled in other public assistance programs with substantially the same income eligibility requirements as the CARE program.

To the extent practicable, the commission shall develop a CARE application process using the existing ULTS application process as a model. The commission shall work with electrical and gas corporations and the Low-Income Oversight Board established in Section 382.1 to meet the low-income objectives in this section.
(2) The commission shall ensure that an electrical corporation or gas corporation with a commission-approved program to provide discounts based upon economic need in addition to the CARE program, including a Family Electric Rate Assistance program, uses a single application form, to enable an applicant to alternatively apply for any assistance program for which the applicant may be eligible. It is the intent of the Legislature to allow applicants under one program, that may not be eligible under that 95 Ch. 61—37 —
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program, but that may be eligible under an alternative assistance program based upon economic need, to complete a single application for any commission-approved assistance program offered by the public utility. (g) It is the intent of the Legislature that the commission ensure CARE program participants receive affordable electrical and gas service that does not impose an unfair economic burden on those participants. (h) The commission’s program of assistance to low-income electric and gas customers shall, as soon as practicable, include nonproﬁt group living facilities speciﬁed by the commission, if the commission ﬁnds that the residents in these facilities substantially meet the commission’s low-income eligibility requirements and there is a feasible process for certifying that the assistance shall be used for the direct beneﬁt, such as improved quality of care or improved food service, of the low-income residents in the facilities.

The commission shall authorize utilities to offer discounts to eligible facilities licensed or permitted by appropriate state or local agencies, and to facilities, including women’s shelters, hospices, and homeless shelters, that may not have a license or permit but provide other proof satisfactory to the utility that they are eligible to participate in the program. (i) (1) In addition to existing assessments of eligibility, an electrical corporation may require proof of income eligibility for those CARE program participants whose electricity usage, in any monthly or other billing period, exceeds 400 percent of baseline usage. The authority of an electrical corporation to require proof of income eligibility is not limited by the means by which the CARE program participant enrolled in the program, including if the participant was automatically enrolled in the CARE program because of participation in a governmental assistance program. If a CARE program participant’s electricity usage exceeds 400 percent of baseline usage, the electrical corporation may require the CARE program participant to participate in the Energy Savings Assistance Program (ESAP), which includes a residential energy assessment, in order to provide the CARE program participant with information and assistance in reducing the CARE program participant’s energy usage. Continued participation in the CARE program may be conditioned upon the CARE program participant agreeing to participate in ESAP within 45 days of notice being given by the electrical corporation pursuant to this paragraph. The electrical corporation may require the CARE program participant to notify the utility of whether the residence is rented, and, if so, a means by which to contact the landlord, and the electrical corporation may share any evaluation and recommendation relative to the residential structure that is made as part of an energy assessment, with the landlord of the CARE program participant.

Requirements imposed pursuant to this paragraph shall be consistent with procedures adopted by the commission.
(2) If a CARE program participant’s electricity usage exceeds 600 percent of baseline usage, the electrical corporation shall require the CARE program participant to participate in ESAP, which includes a residential energy assessment, in order to provide the CARE program participant with information and assistance in reducing the CARE program participant’s 95 —38 — Ch. 61
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energy usage. Continued participation in the CARE program shall be conditioned upon the CARE program participant agreeing to participate in ESAP within 45 days of a notice made by the electrical corporation pursuant to this paragraph. The electrical corporation may require the CARE program participant to notify the utility of whether the residence is rented, and, if so, a means by which to contact the landlord, and the electrical corporation may share any evaluation and recommendation relative to the residential structure that is made as part of an energy assessment, with the landlord of the CARE program participant. Following the completion of the energy assessment, if the CARE program participant’s electricity usage continues to exceed 600 percent of baseline usage, the electrical corporation may remove the CARE program participant from the program if the removal is consistent with procedures adopted by the commission. This paragraph does not prevent a CARE program participant with electricity usage exceeding 600 percent of baseline usage from participating in an appeals process with the electrical corporation to determine whether the participant’s usage levels are legitimate.
(3) A CARE program participant in a rental residence shall not be removed from the program in situations where the landlord is nonresponsive when contacted by the electrical corporation or does not provide for ESAP participation.

SEC. 10. Section 739.9 of the Public Utilities Code is amended to read:
739.9. (a) “Fixed charge” means any ﬁxed customer charge, basic service fee, demand differentiated basic service fee, demand charge, or other charge not based on the volume of electricity consumed. (b) Increases to electrical rates and charges in rate design proceedings, including any reduction in the California Alternate Rates for Energy (CARE) discount, shall be reasonable and subject to a reasonable phase-in schedule relative to the rates and charges in effect before January 1, 2014. (c) Consistent with the requirements of Section 739, the commission may modify the seasonal deﬁnitions and applicable percentage of average consumption for one or more climatic zones.
(d) The commission may adopt new, or expand existing, ﬁxed charges for the purpose of collecting a reasonable portion of the ﬁxed costs of providing electrical service to residential customers. The commission shall ensure that any approved charges do all of the following:
(1) Reasonably reﬂect an appropriate portion of the different costs of serving small and large customers.
(2) Not unreasonably impair incentives for conservation, energy efﬁciency, and beneﬁcial electriﬁcation and greenhouse gas emissions reduction.
(3) Are set at levels that do not overburden low-income customers. (e) (1) For the purposes of this section and Section 739.1, the commission may authorize ﬁxed charges for any rate schedule applicable to a residential customer account. The ﬁxed charge shall be established on an income-graduated basis with no fewer than three income thresholds so that a low-income ratepayer in each baseline territory would realize a lower 95 Ch. 61—39 —
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average monthly bill without making any changes in usage. The commission shall, no later than July 1, 2024, authorize a ﬁxed charge for default residential rates.
(2) For purposes of this subdivision, “income-graduated” means that low-income customers pay a smaller ﬁxed charge than high-income customers.
(f) Notwithstanding the requirements of subdivision (d) of Section 739 and Section 739.7, the commission shall not apply the composite tier method to the treatment of any revenues resulting from any ﬁxed charge adopted pursuant to this section.

SEC. 11. Section 2827.1 of the Public Utilities Code is amended to read:
2827.1. (a) For purposes of this section, “eligible customer-generator,” “large electrical corporation,” and “renewable electrical generation facility” have the same meanings as deﬁned in Section 2827.
(b) Notwithstanding any other law, the commission shall develop a standard contract or tariff, which may include net energy metering, for eligible customer-generators with a renewable electrical generation facility that is a customer of a large electrical corporation no later than December 31, 2015. The commission may develop the standard contract or tariff prior to December 31, 2015, and may require a large electrical corporation that has reached the net energy metering program limit of subparagraph (B) of paragraph (4) of subdivision (c) of Section 2827 to offer the standard contract or tariff to eligible customer-generators.A large electrical corporation shall offer the standard contract or tariff to an eligible customer-generator beginning July 1, 2017, or prior to that date if ordered to do so by the commission because it has reached the net energy metering program limit of subparagraph (B) of paragraph (4) of subdivision (c) of Section 2827.

The commission may revise the standard contract or tariff as appropriate to achieve the objectives of this section. In developing the standard contract or tariff, the commission shall do all of the following:
(1) Ensure that the standard contract or tariff made available to eligible customer-generators ensures that customer-sited renewable distributed generation continues to grow sustainably and include speciﬁc alternatives designed for growth among residential customers in disadvantaged communities.
(2) Establish terms of service and billing rules for eligible customer-generators.
(3) Ensure that the standard contract or tariff made available to eligible customer-generators is based on the costs and beneﬁts of the renewable electrical generation facility.
(4) Ensure that the total beneﬁts of the standard contract or tariff to all customers and the electrical system are approximately equal to the total costs.
(5) Allow projects greater than one megawatt that do not have signiﬁcant impact on the distribution grid to be built to the size of the onsite load if the projects with a capacity of more than one megawatt are subject to reasonable 95 —40 — Ch. 61
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interconnection charges established pursuant to the commission’s Electric Rule 21 and applicable state and federal requirements.
(6) Establish a transition period during which eligible customer-generators taking service under a net energy metering tariff or contract prior to July 1, 2017, or until the electrical corporation reaches its net energy metering program limit pursuant to subparagraph (B) of paragraph (4) of subdivision (c) of Section 2827, whichever is earlier, shall be eligible to continue service under the previously applicable net energy metering tariff for a length of time to be determined by the commission by March 31, 2014. Any rules adopted by the commission shall consider a reasonable expected payback period based on the year the customer initially took service under the tariff or contract authorized by Section 2827.
(7) The commission shall determine which rates and tariffs are applicable to customer generators only during a rulemaking proceeding. Any ﬁxed charges for residential customer generators that differ from the ﬁxed charges allowed pursuant to subdivision (e) of Section 739.9 shall be authorized only in a rulemaking proceeding involving every large electrical corporation.

The commission shall ensure customer generators are provided electric service at rates that are just and reasonable.
(c) Beginning July 1, 2017, or when ordered to do so by the commission because the large electrical corporation has reached its capacity limitation of subparagraph (B) of paragraph (4) of subdivision (c) of Section 2827, all new eligible customer-generators shall be subject to the standard contract or tariff developed by the commission and any rules, terms, and rates developed pursuant to subdivision (b). There shall be no limitation on the amount of generating capacity or number of new eligible customer-generators entitled to receive service pursuant to the standard contract or tariff after July 1, 2017. An eligible customer-generator that has received service under a net energy metering standard contract or tariff pursuant to Section 2827 that is no longer eligible to receive service shall be eligible to receive service pursuant to the standard contract or tariff developed by the commission pursuant to this section.

SEC. 12. Section 17131.20 is added to the Revenue and Taxation Code, to read:
17131.20. (a) For taxable years beginning on or after January 1, 2022, and before January 1, 2027, gross income does not include a bill credit or credits received by a customer from a utility applicant under the 2022 CaliforniaArrearage Payment Program, pursuant to Article 13 (commencing with Section 16429.8) of Chapter 2 of Part 2 of Division 4 of Title 2 of the Government Code.
(b) This section shall remain in effect only until December 1, 2027, and as of that date is repealed.

SEC. 13. Division 29 (commencing with Section 80700) is added to the Water Code, to read:
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DIVISION 29. ELECTRICITY SUPPLY STRATEGIC RELIABILITY

RESERVE PROGRAM
Chapter 1. General Provisions and Definitions
80700. (a) The Legislature ﬁnds and declares all of the following:
(1) California is a leader in driving the affordable and equitable transition to a clean reliable energy system and economy. However, the impacts of climate change are occurring sooner and with more intensity and frequency than previously anticipated.
(2) Extreme events from climate change, including heat waves, wildﬁres, and drought, combined with other factors, such as supply chain disruptions, are jeopardizing California’s ability to build out the electrical infrastructure needed to maintain affordability and reliability.
(3) As California transitions to a clean energy future and contends with climate impacts and other challenges, sufﬁcient capacity of new and existing generation assets will be required to maintain reliability during extreme events.
(4) California must ensure electricity reliability during this period of heightened risk, which includes extraordinary near-term measures and substantive changes to mid-term energy policy, while also ensuring the multifaceted California electrical grid is best positioned to sustainably and equitably achieve California’s clean energy future, climate targets, and air quality requirements.
(b) It is the intent of the Legislature that:
(1) The enactment of this division further the purposes of Chapter 8.9 (commencing with Section 25790) of Division 15 of the Public Resources Code. The development and operation of a program as provided in this division is in all respects for the welfare and the beneﬁt of the people of the state, to protect public peace, health, and safety, and constitutes an essential governmental purpose. This division shall be liberally construed in a manner so as to effectuate its purposes and objectives.
(2) The powers and responsibilities of the department established under this division are not governed by the provisions related to the State Water Resources Development System pursuant to Chapter 8 (commencing with Section 12930) of Part 6 of Division 6, and this division should not constitute a limitation on, or modiﬁcation of, the department’s authority pursuant to Chapter 8 (commencing with Section 12930) of Part 6 of Division 6. 80701. For purposes of this division, the following deﬁnitions apply:
(a) “California balancing authority” has the same meaning set forth in Section 399.12 of the Public Utilities Code.
(b) “Commission” means the State Energy Resources Conservation and Development Commission.
(c) “Load-serving entity” has the same meaning as deﬁned in Section 380 of the Public Utilities Code.
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(d) “Local publicly owned electric utility” has the same meaning as deﬁned in Section 224.3 of the Public Utilities Code.

Chapter 2. Electricity Supply Strategic Reliability Reserve Agreements
80710. (a) The department, in consultation with the commission, shall implement projects, purchases, and contracts to carry out the purposes of Chapter 8.9 (commencing with Section 25790) of Division 15 of the Public Resources Code, including, but not limited to, the Distributed Electricity BackupAssets Program and the Demand Side Grid Support Program. (b) (1) In furtherance of subdivision (a) and notwithstanding any other law, the department may construct, own and operate, or contract for the construction and operation of, contract for the purchase of electricity from, or ﬁnance through loans, reimbursement agreements, or other contracts actions to secure resources for summer reliability or to preserve the option to extend the life of, facilities, including any of the following:
(A) Extension of the operating life of existing generating facilities planned for retirement.
(B) New emergency and temporary power generators of ﬁve megawatts or more. If a generator is operated using diesel fuel, the department shall not operate it after July 31, 2023.
(C) New energy storage systems of 20 megawatts or more that are capable of discharging for at least two hours.
(D) Generation facilities using clean, zero-emission fuel technology of any size to produce electricity.
(E) Supporting the development of zero-emission generation capacity with a point of interconnection at a California balancing authority, with the majority of its capacity contracted for by a load-serving entity that has a service area primarily in California, with an operational date no later than December 31, 2026. For purposes of this subparagraph, only a facility with a net qualifying capacity of at least 50 percent of its nameplate capacity, as estimated at 8:00 p.m. on a date in September, shall be eligible. (2) In furtherance of subdivision (a) of Section 80700, the department may reimburse electrical corporations, as deﬁned in Section 218 of the Public Utilities Code, for the value of imported energy or import capacity products that was (A) delivered or capable of being delivered between July 1, 2022, and on or before September 30, 2022, and (B) was procured at above-market costs or in excess of procurement authorizations set by the Public Utilities Commission and above the requirements needed to serve its bundled customers in support of summer electric service reliability. (c) Facilities constructed by the department or under a contract with the department pursuant to this division shall not constitute State Water Resources Development System facilities under Chapter 8 (commencing with Section 12930) of Part 6 of Division 6.
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(d) (1) The department shall consult with the commission, the Public Utilities Commission, the Independent System Operator or other applicable California balancing authorities, and the State Air Resources Board in carrying out the purposes of this division.
(2) Beginning October 1, 2022, and at least every three months thereafter, the department shall provide an update on the investments made and being considered into the strategic reliability reserve at a commission business meeting.The President of the Public Utilities Commission or the president’s designee and the President of the Independent System Operator or the president’s designee shall attend the presentation.
(3) The department shall prioritize investments that do not compete with generating facilities already planned for development and disclosed by load-serving entities or local publicly owned electric utilities. (4) In fulﬁlling the requirements of this division to achieve electricity reliability, the department shall prioritize investments in feasible, cost-effective zero-emission resources, and then feasible, cost-effective conventional resources.
(e) The department shall develop, execute, and implement contracts covering power generation, operation and maintenance, fuel management, site leases, power settlements, invoice veriﬁcation, billing, and other associated items. The department shall also enter into contracts for external services to provide specialized expertise.
(f) (1) Contracts entered into pursuant to this division, amendments to those contracts during their terms, or contracts for services reasonably related to those contracts, and entered on or before December 31, 2023, shall not be subject to competitive bidding or any other state contracting requirements, shall not require the review, consent, or approval of the Department of General Services or any other state department or agency, and are not subject to the requirements of the State Contracting Manual, the Public Contract Code, or the personal services contracting requirements of Article 4 (commencing with Section 19130) of Chapter 5 of Part 2 of Division 5 of Title 2 of the Government Code.
(2) This subdivision shall not apply to any contract, grant, or loan entered into for purposes of this chapter that does not directly contribute to electrical grid reliability by October 31, 2027.
(3) This subdivision is inoperative December 1, 2026.
(g) For contracts entered into pursuant to this division, amendments to those contracts during their terms, or contracts for services reasonably related to those contracts, and executed after December 31, 2023, Sections 10295, 10297, and 10340 of the Public Contact Code do not apply to a contract that meets the conditions established by the department for those contracts. (h) For contracts entered into pursuant to this division by the department after October 31, 2022, the department shall notify the commission of the terms, costs, and scope at a commission business meeting and the commission shall consider the investment plan for approval in a meeting held consistent with the terms of Chapter 3 (commencing with Section 25200) of Division 15 of the Public Resources Code. No less than 10 days 95 —44 — Ch. 61
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after the commission approves the contract, grant, investment, or loan, the executive director of the commission shall give written notice to the Joint Legislative Budget Committee of the action.
(i) A contract entered into, or an approval granted by, the department pursuant to this division is not subject to the California Environmental Quality Act (Division 13 (commencing with Section 21000) of the Public Resources Code) and regulations adopted pursuant to that act. (j) The department may adopt guidelines to implement this division.The Administrative Procedure Act (Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3 of Title 2 of the Government Code) does not apply to any regulation or guidelines adopted by the department pursuant to this division.
80711. The department, in consultation with the commission, shall recover all of the costs it incurs pursuant to this chapter from the Department ofWater Resources Electricity Supply Reliability Reserve Fund established pursuant to Section 80720. The department and its customers shall not bear any of the costs associated with carrying out the purposes of Chapter 8.9 (commencing with Section 25790) of Division 15 of the Public Resources Code, and those costs shall not be included in the prices, rates, and charges for water and electricity under the water supply contracts executed pursuant to Chapter 8 (commencing with Section 12930) of Part 6 of Division 6. 80712. The department may do any of the following as necessary, as determined by the department, for purposes of this division:
(a) Engage the services of private parties to render professional and technical assistance and advice and other services in carrying out the purposes of this chapter.
(b) Contract for the services of other public agencies. (c) Engage in activities or enter into contracts or arrangements as may be necessary or desirable to carry out the department’s duties and responsibilities pursuant to this division.
(d) Hire personnel necessary and desirable for the timely and successful implementation and administration of the department’s duties and responsibilities pursuant to this division.The State Personnel Board and the Department of Human Resources shall assist the department in expediting that hiring.

Chapter 3. Department of Water Resources Electricity Supply Reliability Reserve Fund
80720. (a) There is hereby established in the State Treasury the Department of Water Resources Electricity Supply Reliability Reserve Fund. (b) Notwithstanding Section 13340 of the Government Code, all moneys in the fund are continuously appropriated to the department, without regard to ﬁscal years, and shall be available for the purposes of Chapter 2 (commencing with Section 80710).
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(c) Obligations authorized and expenses incurred by the department in administering this division shall be payable solely from the fund. (d) All revenues payable to the department for activities undertaken by the department under Chapter 2 (commencing with Section 80710) shall be deposited into the fund.
(e) The fund shall be separate and distinct from any other fund and moneys administered by the department and any interest earned on the moneys in the fund shall be used solely for purposes of this division. (f) When ﬁxed assets procured under the authority of this division are sold or otherwise disposed of, the revenue from the sale or disposition, including any gain or loss, measured by the difference between book value and selling price, shall be deposited into the fund and available to the department for purposes of Chapter 2 (commencing with Section 80710).

Any remaining revenue from the sale or other disposition of ﬁxed assets procured under the authority of this division shall be returned to the General Fund once all obligations of the department are satisﬁed after the wind down of this division and the closure of the fund. While any obligation of the department incurred under this division remains outstanding and not fully performed or discharged, the rights, powers, duties, and existence of the department shall not be diminished or impaired in any manner that will adversely affect the interests and rights of the holders of or parties to those obligations.

Chapter 4. Miscellaneous
80730. Beginning on January 31, 2023, and every May 1, August 1, and December 1 annually thereafter, the department shall issue a written report to the Joint Legislative Budget Committee, detailing the actions undertaken by the department in the period since the previous report was submitted pursuant to this division and up until that date, including, but not limited to, all of the following:
(a) Amount of funds expended.
(b) Purpose of funds expended.
(c) Status of actions funded.
(d) For new and expanded resources, the amount by megawatt, resource type, operational date, and expected lifetime of that capacity. (e) The frequency at which resources funded by the department have been used and the extent to which they complied with the requirements of this chapter.
(f) In consultation with the state board, estimate or provide the best available information on the emissions of greenhouse gases, criteria air pollutants, and toxic air contaminants emitted by the resources funded by the department over the period since the previous report. (g) Summary of contracts, grants, and loans issued pursuant to this division.
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SEC. 14. (a) In regards to Section 739.9 of the Public Utilities Code, as amended by this act, the Legislature ﬁnds and declares all of the following:
(1) The Public Utilities Commission has found that electrical corporation customers are facing two areas of increasing cost pressures: growing electric transmission and distribution infrastructure and operation costs, including wildﬁre mitigation costs, and equitable recovery of utility ﬁxed costs. (2) The majority of an electrical corporation’s revenue requirement, including funds for electric generation, transmission and distribution investments, and operations and maintenance work, is recovered from customers by a volumetric rate. However, only a portion of the electrical corporation’s costs directly vary based on how much electricity a customer consumes, while many infrastructure and operational costs do not. (3) The current default residential customer rate structure in electrical corporation territories leads to a situation in which rates must rise to recover sufﬁcient revenue to support certain ﬁxed utility costs and can lead to year-to-year rate increase volatility, especially with declines in electricity sales that result from greater adoption of distributed energy resources. (4) The disparity between volumetric revenue recovery and ﬁxed costs that do not vary with electricity consumption also contributes to potential inequities among customers.
(b) In regards to Section 739.9 of the Public Utilities Code, as amended by this act, it is the intent of the Legislature to do both of the following:
(1) Authorize the Public Utilities Commission to establish reasonable ﬁxed charges on default residential customer rates to help stabilize rates and equitably allocate and recover costs among residential customers in each electrical corporation’s service territory.
(2) If the Public Utilities Commission establishes ﬁxed charges on default residential customer rates, ensure that the ﬁxed charges are established to more fairly distribute the burden of supporting the electric system and achieving California’s climate change goals through the ﬁxed charge.

SEC. 15. (a) For the purposes of complying with Section 41 of the Revenue and Taxation Code, with respect to Section 17131.20 of the Revenue and Taxation Code, as added by this act, the Legislature ﬁnds and declares that the purpose of the exclusion allowed by Section 17131.20 of the Revenue and Taxation Code is to provide ﬁnancial relief to California residents, to alleviate, in part, the adverse impacts of the economic disruptions and hardships resulting from the COVID-19 emergency. (b) In order to provide information on the exclusion allowed by Section 17131.20 of the Revenue and Taxation Code, the Department of Community Services and Development shall prepare a written report that includes the number of households receiving a 2022 CAPP beneﬁt as provided in accordance with the 2022 California Arrearage Payment Program (Article 13 (commencing with Section 16429.8) of Chapter 2 of Part 2 of Division 4 of Title 2 of the Government Code).

SEC. 16. The provisions of this act are severable. If any provision of this act or its application is held invalid, that invalidity shall not affect other 95 Ch. 61—47 —
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provisions or applications that can be given effect without the invalid provision or application.

SEC. 17. No reimbursement is required by this act pursuant to Section 6 of Article XIIIB of the California Constitution because a local agency or school district has the authority to levy service charges, fees, or assessments sufﬁcient to pay for the program or level of service mandated by this act or because costs that may be incurred by a local agency or school district will be incurred because this act creates a new crime or infraction, eliminates a crime or infraction, or changes the penalty for a crime or infraction, within the meaning of Section 17556 of the Government Code, or changes the deﬁnition of a crime within the meaning of Section 6 of Article XIIIB of the California Constitution.

SEC. 18. (a) The sum of two hundred million dollars ($200,000,000) is hereby appropriated from the General Fund to the State Energy Resources Conservation and Development Commission for the 2021–22 ﬁscal year.

These funds shall be used for a program to provide incentives for demand side grid support and associated mitigation costs.
(b) With these funds, the State Energy Resources Conservation and Development Commission may do any of the following:
(1) Adopt regulations, guidelines, or other standards for the program at a State Energy Resources Conservation and Development Commission business meeting. The Administrative Procedure Act (Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3 of Title 2 of the Government Code) does not apply to regulations, guidelines, or other standards for the program adopted at the State Energy Resources Conservation and Development Commission business meeting. (2) Use any type of third-party block grant or contract with incentive program implementers for the purposes of implementing the program. (3) Advance up to 25 percent of the awarded funds at a time to parties that are eligible for funding for purposes of the program. (c) Contracts, grants, or loans entered into with these funds shall not require the review, consent, or approval of the Department of General Services or any other state department or agency and do not need to comply with requirements under the State Contracting Manual, the Public Contract Code, or the contracting requirements of Article 4 (commencing with Section 19130) of Chapter 5 of Part 2 of Division 5 of Title 2 of the Government Code.
(d) These funds shall be available for encumbrance or expenditure by the State Energy Resources Conservation and Development Commission until June 30, 2026, and shall be available for liquidation until June 30, 2030.

SEC. 19. This act is a bill providing for appropriations related to the Budget Bill within the meaning of subdivision (e) of Section 12 of Article IV of the California Constitution, has been identiﬁed as related to the budget in the Budget Bill, and shall take effect immediately.

O
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Proceeding.:R.22-07-005
Exhibit No.: Joint IOUs-01
Witnesses: See Table of Contents
Joint Testimony of Southern California Edison
Company, Pacific Gas and Electric Company, and
San Diego Gas & Electric Company (the Joint IOUs)
Describing Income-Graduated Fixed Charge
Proposals
Joint IOUs’ Exhibit 1, addressing:
- Policy
- Rate Design
- Income Verification
- Implementation
- Marketing
- Cost Recovery
Before the
Public Utilities Commission of the State of California
April 7, 2023
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EXHIBIT 3

Testimony Describing Joint IOUs’ Income-Graduated
Fixed Charge Proposals
Table Of Contents
Section Page Witness

-i-
I. POLICY .......................................................................................................1 M. Backstrom A. Introduction ......................................................................................1 B. The Joint IOUs’ Residential Rate Proposals Comply with Assembly Bill 205............................................................................2

1. Benefits of the Joint IOUs’ Proposals Compared
to Current Residential Rates ................................................6 a) Improving Equity by Bringing Rates Closer to
Cost of Service. ............................................................... 6 b) Addressing Affordability and Protecting Low-
Income Customers. ......................................................... 8 c) Encouraging Beneficial Electrification. ........................ 10 d) Promoting Bill Stability and Maintaining
Strong TOU Price Signals. ............................................ 14

2. The Joint IOUs’ Proposals Will Apply to All
Residential Rate Schedules ................................................15

3. The Joint IOUs’ Proposals Are Consistent with
Rate Design Principles. ......................................................16 C. The Joint IOUs’ Proposals Should be Adopted as Soon as Possible. .........................................................................................18 D. Income Verification Should Be Performed By State
Agencies and Not The IOUs ..........................................................18 E. Robust Marketing, Education, and Outreach Will be
Required .........................................................................................20 F. Conclusion .....................................................................................21 II. RATE DESIGN .........................................................................................22 G. Morien R. Thomas
C. Kerrigan
A. Introduction ....................................................................................22

1. Summary of Proposals .......................................................22 B. Background ....................................................................................24

1. Recent Rate Design Policy Issues ......................................24

2. Next 10 Research on Potential Fixed Charges ...................28

3. The Joint IOUs’ Proposals Align with
Modernized Rate Design Principles ...................................32 10/24/2023 D3 52 of 196

Testimony Describing Joint IOUs’ Income-Graduated
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Section Page Witness
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C.Basis for the Average IGFC Level .................................................34

1.Methodology for Determining Average Fixed
Charge Level ......................................................................34 D.Income Graduated Fixed Charge Discount Levels ........................42

1.Summary ............................................................................42 a)Lower Average Monthly Bills for Low-
Income Customers ........................................................ 43 E.Impact of the IGFC on Rates and Other Rate Design
Issues ..............................................................................................44

1.Impact of the IGFC on Volumetric Rates ..........................44

2.Adjusting the IGFC Over Time for Revenue
Requirement Changes ........................................................45

3.IGFC Review and Assessment Over Time ........................46

4.CARE Discount Structure Changes ...................................47

5. FERA Interaction with IGFC .............................................49

6.Implementation of the IGFC on Non-Default
Residential Rates ................................................................50

7. Size Differentiation ............................................................51

8.Elimination of Minimum Bills ...........................................53 B.Calibration Mechanism for Structure Revisit ................................53 C.Public Tool Results ........................................................................54 III.INCOME VERIFICATION .......................................................................55 R. Alvarez C. Coughlan
M.Fischlein
A.Introduction ....................................................................................55

1.Income Assignment and Verification - Objectives
and Evaluation Criteria ......................................................55 D.Stakeholder Input ...........................................................................58

1. Key Stakeholder Input .......................................................58 E.Income Definition ..........................................................................58 F.Household Income Brackets ..........................................................59 G.Income Verification Options Evaluated by the Joint IOUs ...........60

1.Introduction ........................................................................60

2.Using Current Program Information ..................................61

3. Using Available State Processes ........................................62 10/24/2023 D3 53 of 196

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a) DSS’s “CalFresh Confirm” Data .................................. 62 b)CPUC/ Third Party LifeLine Low Income
Program for Telecom Utilities ...................................... 64

4. Using Credit Agency Data .................................................65

5.Using Customer Stated or Verified Income Data ..............68

6.IOU Developed Data Model ..............................................73

7. Key Findings on Evaluated Options ..................................74

8.Recommendation ...............................................................76 H.Income Verification and Appeals Process .....................................78

1.Income Verification Ownership and
Implementation ..................................................................78

2.High Level Utility Process Overview ................................82 a)Initial Income Bracket Assignment .............................. 82 b)Appeals Process and Customer-Initiated
Income Updates ............................................................ 85 c)Periodic Refresh ............................................................ 89 I.Currently Projected Costs of Joint IOUs’ Proposal .......................89 J.Anticipated Costs for CPUC-Supervised Third Party
Income Verification .......................................................................90

1.High-Level Cost Estimates for the Other Major
Scenarios Evaluated but not Recommended – In-
House IOU Income Verification ........................................93 K.Timeline for Implementation of Third-Party Income
Verification ....................................................................................94 IV.IMPLEMENTATION ................................................................................96 N. Kane M.McCutchan
E.Molnar
A.Introduction ....................................................................................96 B.Implementation Objectives and Plan Overview ............................97 C.Billing Information Technology System Changes .........................98

1. Implementation Timing ...................................................100

2.Approach to Transitioning Customers .............................102

3.Updates to Current Customer-Facing Tools ....................103

4. New Tools ........................................................................103 D.Coordination with Community Choice Aggregators ...................104 10/24/2023 D3 54 of 196

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E. Customer Support Resources - Contact Centers ..........................104 F. Costs .............................................................................................105

1. Implementation Costs ......................................................105

2. Measurement and Evaluation ...........................................107 G. High-Level Estimates of Timing and Cost for Other
Anticipated Proposals ..................................................................107 V. MARKETING EDUCATION & OUTREACH ......................................109 A. Bernhardt B. Kopec
E. Wasmund
A. Introduction ..................................................................................109 B. Research Insights .........................................................................109

1. PG&E ...............................................................................109 a) Stimuli ..............................................................................110 b) Key Findings ....................................................................111

2. SDG&E ............................................................................113

3. SCE ..................................................................................113 C. Joint IOU ME&O Proposal’s Objectives .....................................114 D. Lessons Learned from Residential Time-of-Use
Transition Inform IGFC Outreach Strategies ..............................115 E. Plans to Refine Outreach Plans Based on Findings from Additional Research .....................................................................117 F. Target Audiences .........................................................................117 G. Rollout and Implementation ........................................................118 H. Messaging Phases and Customer Journey ...................................120 I. Integrated Campaign Tactics .......................................................122 J. Community Outreach Tactics ......................................................125

1. Community Based Outreach (CBO) ................................125

2. Joint IOU Employee Outreach .........................................126

3. External Stakeholders: .....................................................126 K. Metrics and Tracking ...................................................................126 L. Budget ..........................................................................................126 10/24/2023 D3 55 of 196

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VI. COST RECOVERY .................................................................................128 R. Madsen G. Morien
E. Pulgar
A. Introduction ..................................................................................128 B. Cost Recovery and Rate Making Proposal ..................................130

1. Cost Recovery Advice Letters Filings .............................130

2. Income Graduated Fixed Charge Balancing
Account (IGFCBA) ..........................................................131

1. Recovery of the IGFCBA Via the PPP Rate
Component .......................................................................134

2. Recovery of Income Verification Costs through
State Funding ...................................................................134 C. Recovery of Authorized Costs via the IGFC ...............................135 D. IGFC Calibration Mechanism ......................................................136 10/24/2023 D3 56 of 196

Testimony Describing Joint IOUs’ Respective Income-Graduated Fixed Charge Proposals
List Of Tables
Table Page

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Table I-1 Illustrative Proposed IGFCs ..............................................................................................5 Table II-2 Illustrative Proposed IGFCs ............................................................................................24 Table II-3 Illustrative Summary of Impacts to Default Rates ..........................................................24 Table II-4 PG&E Default Rates Compared to Marginal Cost Metrics ............................................35 Table II-5 Illustrative Fixed Cost Revenue Requirement Categories in the Public Tool ($/month charge) – Residential Non-CARE Customers ............................37 Table II-6 Revenue Requirement Categories Underlying the Joint IOUs’ Proposed Fixed Charges and Resulting Reductions in the Volumetric Rate Component ........................................................................................................................................38 Table II-7 IOUs’ Volumetric Rate Adjustment Methodology by Rate Schedule ............................44 Table II-8 SDG&E Illustrative CARE Bill Comparison .................................................................48 Table II-9 SCE Illustrative CARE Bill Comparison ........................................................................48 Table II-10 PG&E Illustrative CARE Bill Comparison ..................................................................48 Table III-11 Joint IOUs Percentage of Residential Customers by Income Brackets .......................60 Table III-12 Summary of Each Joint IOU’s Internal Costs to Support our Recommended CPUC-Supervised Third-Party Approach to IGFC Income Verification ........................................................................................................................................90 Table III-13 Comparison of Third Party Income Verification Implementation Costs ....................92 Table IV-14 Joint IOU Residential Rates Impacted by IGFCs ........................................................99 Table IV-15 Implementation Milestones ........................................................................................102 Table IV-16 Estimated Implementation Costs by IOU ...................................................................106 Table V-17 Useful Lessons from Residential Default TOU Transition to Inform IGFC ...............116 Table V-18 Joint IOUs’ Proposed Phased IGFC Communication Sample ....................................120 Table V-19 Initial Estimates of ME&O Costs, by IOU ..................................................................127

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List Of Figures
Table Page

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Figure I-1 Residential Rate Design Across the U.S. .........................................................................8 Figure I-2 Average Annual Percent Difference by Income Bracket ................................................10 Figure I-3 California’s Decarbonization Accomplishments and Future Goals ...............................11 Figure I-4 Current California GHG Emissions Inventory Data .......................................................12 Figure I-5 SCE Example: Non-CARE Inland Income Bracket 3 Customer Energy Burden Comparison .......................................................................................................14 Figure II-6 2021 Next 10 Report Theoretical Fixed Charges - PG&E ............................................30 Figure III-7 Proposed High Level Chart of Entities Involved In Administration and Implementation of Income Bracket Assignment and Appeal Process ...................81

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1 I. 1
POLICY 2
A. Introduction 3
Current residential rate structures based primarily on volumetric rates do not reflect cost 4 of service, are not equitable, and do not send appropriate price signals to encourage broader 5 adoption of greenhouse gas (GHG) reducing technologies. The artificially high volumetric rates 6 in existing residential rate structures pose affordability challenges for many lower- and 7 moderate-income customers, very high bills for larger users, and monthly bill volatility. 8 In contrast, the Joint IOUs’ proposals to combine an Income Graduated Fixed Charge 9 (IGFC) with lower volumetric rates on all residential rate schedules will improve equity. Our 10 proposals will bring customers’ rates closer to the cost to serve them, result in greater month-to-11 month bill stability, and provide low-income customers with bill reductions, on average, relative 12 to the current rate structure. The lower volumetric rates will also encourage decarbonization by 13 making transportation and building electrification more affordable. More cost-based electricity 14 prices will compare more favorably to prices of gasoline and natural gas. As detailed in the 15 remainder of this chapter, these reformed residential rate structures are urgently needed to 16 support achievement of the state’s decarbonization goals. 17 The Joint IOUs’ proposals are designed to support the policy goals discussed, and since 18 customer acceptance of rate reform is key, continued customer research and marketing, 19 education, and outreach (ME&O) is needed to ensure customers have a positive experience. The 20 Joint IOUs’ proposed outreach and communication will make the reformed rate structures 21 transparent and understandable to customers and explain the expected overall benefits. 22 An important part of the Joint IOUs’ proposal is the recommendation that income 23 verification for purposes of assigning customer households to the appropriate IGFC level be 24 administered by a Third Party contractor supervised by the California Public Utilities 25 10/24/2023 D3 59 of 196

2 Commission (CPUC or Commission), as is done for the LifeLine program for 1 telecommunication companies.1 The Joint IOUs today perform a limited form of income 2 verification in the narrow context of opt-in discount programs such as the California Alternate 3 Rates for Energy (CARE) program (where customers agree in their application to provide 4 requested income information, in order to qualify). However, the process of assigning all of 5 California’s residential electric customers to income categories is unprecedented, and requires 6 capabilities and processes that are best administered by a state agency – and are far beyond prior 7 utility experience and capabilities. Adding the resources and systems necessary for the energy 8 utilities to perform such income validation would not be cost effective. Doing so also raises 9 sensitive issues of consumer privacy, cybersecurity, and utility-customer relations. For these 10 reasons, as described in Chapter 3 of this Exhibit, income verification should be overseen by a 11 state agency, such as the CPUC, and likely conducted by a qualified third party that would apply 12 the necessary protocols to ensure a fair and positive customer experience. 13 B. The Joint IOUs’ Residential Rate Proposals Comply with Assembly Bill 205 14 In mid-2022, the California legislature, through Assembly Bill (AB) 205, removed the 15 statutory language requiring default residential rates to be almost exclusively charged on a 16 volumetric basis and provided a framework to make the residential electricity rate structure more 17 equitable. That bill’s amendments to Public Utilities Code § 739.9 now allow the CPUC to take 18 the next step in needed residential electric rate reforms, by collecting through a set IGFC costs 19 that do not vary volumetrically or are more equitability collected in a fixed charge. A fixed 20 charge alone results in volumetric rates more in line with cost of service, which help to control 21 high bills and bill volatility associated with event-driven higher usage, and greatly enhance the 22 widespread electrification efforts needed to achieve our state’s GHG reduction goals. AB 205 23 aims to offer all customers better price signals while also providing additional affordability 24

1 See R.22-07-005, Phase 1 Track A: Income-Graduated Fixed Charge Guidance Memo at p. 9. 10/24/2023 D3 60 of 196

3 protections for low-income customers through the IGFC. The Joint IOUs and other parties have 1 already briefed the CPUC on statutory interpretation issues relating to AB 205. Because the 2 CPUC has not yet ruled on those AB 205 legal issues, each party was directed to assume that its 3 own brief’s recommended interpretation of the statute is adopted. That directive was followed 4 herein as well as in each of the Joint IOUs’ individual rate calculations. 5 The Joint IOUs have developed a common, modernized rate design structure that 6 balances several key objectives, including supporting increased affordability for lower- and 7 moderate-income customers while also helping the state achieve its decarbonization goals in a 8 more equitable and affordable manner relative to the status quo. 9 The Joint IOUs have worked together, in collaborative discussion with a wide range of 10 other parties (including through Energy Division workshops) to carefully consider a range of 11 potential IGFC approaches. While each IOU is separately providing individual Rate Design 12 Exhibits based on its unique revenue requirements, customer distributions, and service options, 13 all proposals are guided by the following key principles: 14  Provide a better aligned cost-based residential rate structure that collects costs in a 15 more equitable manner from all customers through an IGFC; 16  Support a more progressive residential rate structure for customers that matches 17 income ranges with the level of monthly fixed charge each customer pays, providing 18 affordability and bill relief for vulnerable lower income customers through lower 19 volumetric rates and the IGFC; 20
 Encourage electrification by reducing volumetric rates for all customers, providing a 21 stronger economic basis in electric rates for customers to adopt cleaner electrification 22 technologies; 23
 Provide increased bill stability for customers because a portion of a customer’s bill 24 will remain flat and predictable from month to month; and 25 10/24/2023 D3 61 of 196

4  Maintain strong price signals during critical energy and grid hours through time-of-1 use (TOU) rate differentials that encourage customers to save by shifting use out of 2 these high-cost hours. 3
Today, lower- and moderate-income customers, on average, pay a greater percentage of 4 their income towards their electricity bill relative to higher income customers.2 The Joint IOUs’ 5 proposals result in meaningful bill savings for these customers, with no change in usage. (See 6 Figure I-2 below.) As customers adopt environmentally-beneficial electrification technologies in 7 accordance with state policy, the Joint IOUs’ proposals significantly reduce volumetric rates and 8 make these new technologies more financially attractive.3 Importantly, these rates would be 9 technology-agnostic, making them more flexible and available for all customers. The Joint 10 IOUs’ proposals also consider how best to balance competing considerations to make income 11 verification as accurate as possible, while also aiming for a cost-effective implementation of a 12 major structural change for all residential customers. 13 As described in the previously submitted briefs, the Joint IOUs interpret AB 205’s “no 14 fewer than three income thresholds” language to mean there must be at least three Income 15 Brackets. The Joint IOUs are proposing four household Income Brackets to achieve greater 16 progressivity by offering further relief to the most economically vulnerable households with the 17 highest energy burdens – those with incomes less than or equal to 100% of the Federal Poverty 18 Level (FPL). This strikes an appropriate balance, implementing a progressive IGFC structure 19 while minimizing the operational challenges inherent in having too many income brackets. 20 Specifically, the Joint IOUs propose the following four household Income Brackets: 21  Bracket 1 – CARE customers with incomes less than 100% of FPL; 22

2 Next 10 and Energy Institute at Haas, University of California, Paying for Electricity in California:

How Residential Rate Design Impacts Equity and Electrification (hereinafter Next 10, Paying for Electricity in California) (Sept. 2022), available at https://www.next10.org/sites/default/files/2022- 09/Next10-paying-for-electricity-final-comp.pdf.
3 See Chapter 2 (Rate Design) for impact to volumetric rates. 10/24/2023 D3 62 of 196

5  Bracket 2 – Remaining CARE and Family Electric Rate Assistance (FERA) enrolled 1 customers; 2
 Bracket 3 – Non-CARE or FERA customers with incomes up to or equivalent to 3 650% of FPL; and 4
 Bracket 4 – Non-CARE customers with incomes above 650% of FPL. 5 While it is important to maintain affordability for the most vulnerable low-income 6 customers, it is also imperative that the overall average fixed charge across all four income 7 categories be sufficient to enable meaningful reductions in volumetric rates that incentivize 8 customer electrification efforts. Because each of the Joint IOUs has its own, CPUC-adopted, 9 marginal costs of service, the application of the proposed basic rate design structure described 10 here results in differing calculations of each Joint IOU’s specific fixed charges by household 11 Income Bracket. The illustrative proposed IGFCs for each of the Joint IOUs are shown in Table 12 I-1 below and the appendices to this Joint Testimony present the individual rate designs for each 13 IOU’s residential rate schedules. 14
Table I-1
Illustrative Proposed IGFCs

Income
Bracket
Criteria PG&E
IGFC
($/month)
SDG&E
IGFC
($/month)
SCE
IGFC
($/month)
Average Fixed Charge $53 $74 $49
1 CARE ( 650% FPL $92 $128 $85
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6 1. Benefits of the Joint IOUs’ Proposals Compared to Current Residential 1 Rates 2
The Joint IOUs’ proposals provide several benefits compared to the current, primarily 3 volumetric, rate structures for the IOUs’ residential electric customers. These are described in 4 the sections below. 5
a) Improving Equity by Bringing Rates Closer to Cost of Service. 6 While the energy environment in California continues to evolve rapidly, the residential 7 rate structure for investor-owned, regulated utilities has become outdated and misaligned with 8 the new energy landscape. Unlike many utilities nationwide, and publicly-owned utilities within 9 California,4 nearly all of the Joint IOUs’ costs to serve their residential customers are collected 10 through cent-per-kilowatt hour (kWh) volumetric rates, even though approximately two-thirds of 11 these residential costs are either fixed or do not fluctuate as customer usage increases or 12 decreases.5 CPUC-approved residential rates also differ markedly from the rate schedules that 13 the Commission has approved for the Joint IOUs’ non-residential customers, which almost 14 universally include a separate fixed charge component to recover fixed costs on a non-volumetric 15 basis. 16
Existing residential rate design policies are under review in this proceeding, as they were 17 based on priorities that do not sufficiently align with a focus on improving the affordability of 18 electric service and more equitably recovering fixed costs, as the state seeks to expand beneficial 19 electrification. Whereas in the past, state law encouraged the CPUC to land on the side of rate 20 design resulting in higher volumetric rates, now the CPUC is required to balance, providing 21 appropriate price signals, both energy use reduction and energy use increases where such 22

4 For example, the Sacramento Municipal Utility District (SMUD) charges a $23.50 monthly fixed charge on both Rate Schedule R (Fixed Rate) and Rate Schedule R-TOD (Residential Time-of-Day Service). See https://www.smud.org/en/Rate-Information/Residential-rates . 5 Fixed revenue requirements as a portion of total residential revenue requirement, averaged across IOUs.
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7 increases would support GHG emissions reductions. This statutory change endorses the end of 1 the longstanding presumption that costs should be predominantly recovered through volumetric 2 rates for most residential customers. Instead, the priority is that volumetric price signals should 3 enable customers to make decisions that are better aligned with the State’s climate goals. 4 As the Joint IOUs continue to build and maintain necessary critical infrastructure to help 5 enable California’s energy transition, collecting residential customers’ fixed costs through 6 volumetric rates unfairly shifts fixed costs from lower to higher-use customers and 7 disincentivizes beneficial uses of electricity. Because nearly all the Joint IOUs’ fixed costs are 8 recovered through such volumetric prices, the price customers pay when they turn on their lights 9 is substantially higher than the marginal cost of providing that electricity. A recent paper from 10 the Energy Institute at Haas, UC Berkeley and Next 10 highlights that volumetric electricity rates 11 in California are two to three times the marginal cost of providing electricity.6 Indeed, this 12 heavily volumetric residential rate design is a significant outlier when looking at residential rate 13 design across the U.S. as shown in Figure I-1 below. 14

6 Next 10 and Energy Institute at Haas, Designing Electricity Rates for an Equitable Energy Transition (Feb. 2021), available at https://haas.berkeley.edu/wp-content/uploads/WP314.pdf . 10/24/2023 D3 65 of 196

8 Figure I-1
Residential Rate Design Across the U.S.7

Fixed and mandated public policy costs should be collected in fixed charges. The Joint 1 IOUs’ proposals address the inequity currently embedded in a primarily volumetric residential 2 rate structure, through the introduction of the IGFC. The proposed fixed charge levels in each 3 household Income Bracket have been set to yield an overall average fixed charge across all 4 household income levels that provides meaningful volumetric rate reductions while including an 5 appropriate portion of fixed system costs in the charge. The resulting IGFC revenues bring 6 volumetric rates closer to the actual cost of providing service to customers8 – and provide relief 7 from high summer bills for high-usage households living in hotter climates. As described below, 8 lower volumetric rates also will be vital to enabling electric appliances/equipment/vehicles to 9 better support the transition to a decarbonized economy. 10 b) Addressing Affordability and Protecting Low-Income Customers. 11 Introducing even a traditional non-income-graduated fixed charge coupled with lower 12 volumetric rates would support California’s GHG policy goals and recover costs more equitably 13

7 Borenstein and Bushnell, National Bureau of Economic Research, Do Two Electricity Pricing Wrongs Make a Right? Cost Recovery, Externalities, and Efficiency (Rev. Sept. 2018), available at https://www.nber.org/papers/w24756 .
8 See Chapter 2 Joint Rate Design Chapter.
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9 than today’s rate structure, including producing lower bills for high users and higher bills for low 1 users, independent of their household income levels. However, the progressive nature of the 2 IGFC, mandated by AB 205 – with higher-income customers paying higher monthly fixed 3 charges than lower-income customers – also mitigates the adverse bill impacts that a traditional 4 fixed charge might have on lower-usage low-income customers. In particular, creating four 5 household Income Brackets, as opposed to three, allows the Joint IOUs to create an Income 6 Bracket available to our most economically vulnerable customers (those who fall under 100% of 7 the FPL), who will pay very modest monthly fixed charges while further benefitting from 8 significantly lower volumetric charges. 9
While the Joint IOUs have proposed to substantially reduce volumetric electricity rates 10 for all residential customers, the proposals also recognize many customers may not be able to 11 electrify in the near term. A key priority of the Joint IOUs’ proposals is to provide bill savings 12 for customers in Income Brackets 1-3 today. The IGFC proposals provide annual bill savings for 13 these customers, on average, without changing their energy consumption. 14 As shown in Figure I-2, on average, the Joint IOUs’ customers in Income Brackets 1-3 15 (lowest to moderate household income) are estimated to save between 4% to 21% per year, or 16 $89-$300 respectively, based the results of the E3 Public Tool (Public Tool) provided by the 17 Energy Division as part of this proceeding. 18
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10 Figure I-2
Average Annual Percent Difference by Income Bracket

The Joint IOU proposals can achieve these savings for customers in Income Brackets 1-3 1 through the difference in the IGFC paid by Income Bracket 4 customers relative to Income 2 Bracket 1-3 customers. All customers can benefit from the lower volumetric rates but Bracket 1-3 3 customers pay a lower IGFC, allowing them to see immediate savings, on average, versus the 4 current status quo. In Income Bracket 4, customers with higher usage, such as that resulting 5 from electrification adoption, will also have lower bills than they would under today’s rate 6 structure, on average. 7
c) Encouraging Beneficial Electrification. 8
While California has made great strides in reducing GHG emissions in recent years, the 9 state must decarbonize twice as fast over the next two decades to meet its 2045 goals, as shown 10 in Figure I-3. 11
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11 Figure I-3
California’s Decarbonization Accomplishments and Future Goals9

Widespread electrification of customer homes and vehicles will be critical in accelerating 1 the pace of decarbonization. As shown in Figure I-4 below, based on 2020 emissions data, these 2 two sectors –-- transportation and buildings (residential and commercial) – represent nearly 50% 3 of California’s GHG inventory as reported. Customer adoption of beneficial electrification 4 technologies is essential to effectively reduce the greenhouse gas emissions currently associated 5 with these two sectors. 6

9 See California Air Resources Board (CARB) 2000 – 2020 GHG Inventory (2022 edition, by economic sector), MMTCO2e = Million metric tons of carbon dioxide equivalent.

Historical rate of reduction calculated from 2010 – 2020. 10/24/2023 D3 69 of 196

12 Figure I-4
Current California GHG Emissions Inventory Data10

1 Powered by increasingly clean electricity, electrification will help replace traditional 2 fossil fuel technologies and their emissions with more climate-friendly, decarbonized 3 alternatives. Electric technologies produce fewer emissions than alternatives powered by fossil-4 fuels such as petroleum and natural gas; this environmental advantage of electricity will continue 5 to grow as greater amounts of carbon-neutral electric generation resources are added to the grid, 6 in compliance with state law. 7
As California looks to encourage customers to efficiently use more electricity, volumetric 8 rates that are significantly higher than the actual cost of providing that electricity create an 9 economic disincentive for the adoption of electrification technologies.11 A fully electrified 10

10 See CARB, Greenhouse Gas Emission Inventory - 2022 Edition. Building represents both Commercial and Residential sectors. Other includes High Global Warming Potential Gases and Recycling & Waste, available at https://ww2.arb.ca.gov/ghg-inventory-data . 11 Inclining-block tiered rates are especially problematic in this regard, charging artificially inflated rates for usage in the upper tiers – precisely the tiers that customers who substitute electric appliances for those powered by fossil fuels are likely to end up in. 10/24/2023 D3 70 of 196

13 home12 is estimated to increase a customer’s electricity usage by at least 70% per month relative 1 to their prior usage. 13 While such increased usage reduces net greenhouse gas emissions, when 2 coupled with some of the highest volumetric rates in the U.S., a customer’s monthly electric bill 3 under current default residential rate designs would dramatically increase. Without reform, the 4 current volumetric rate design will jeopardize the state’s ability to decarbonize rapidly and could 5 put the achievement of our GHG reduction goals at risk. 6 In contrast, by significantly reducing volumetric electric rates – and thus the incremental 7 electric costs to customers due to installing clean electric appliances – the Joint IOUs’ proposals 8 will spur electrification adoption by making such appliances and electric vehicles (EVs) more 9 affordable versus the status quo rate structure. For example, when purchasing an EV, a critical 10 consideration is the electric rate the consumer would pay to charge it. Lower per-kWh rates have 11 been found to increase electric vehicle adoption.14 Specifically, a 1 cent per kilowatt-hour 12 decrease in electric rates has been found to lead to about a 2 percent increase in electric vehicles 13 sales.15 Similarly, lower electric rates have been correlated with higher electric heating adoption. 14 In fact, by lowering the volumetric rate to the marginal cost of energy, home heating 15 electrification was predicted to increase by one-third in California.16 16 The Joint IOUs’ proposals make electrification more attractive than the status quo by 17 helping incentivize adoption through lower volumetric rates, while also avoiding cross subsidies 18 for those unable to adopt new technologies. As illustrated in Figure I-5, a Bracket 3 customer 19

12 A fully electrified home is assumed to have heat pump water heater, heat pump for space heating and cooling, fully electrified appliances, and one EV.
13 The increase in electricity usage for a fully electrified home is calculated from the Public Tool comparing a fully electrified home with one EV to a mixed-used fuel home with one gasoline powered vehicle for a SCE Inland customer.
14 A. Soltani-Sobh, K. Heaslip, A. Stevanovic, R. Boswarth , D. Radivojevic, Analysis of the Electric Vehicles Adoption over the United States, (2017), available at https://www.sciencedirect.com/science/article/pii/S235214651730162X . 15 J. Bushnell, E. Muehlegger, D. Rapson, Do Electricity Prices Affect Electric Vehicle Adoption?, (May 2021), available at https://escholarship.org/uc/item/5f80503b . 16 Next 10 Paying for Electricity in California, at p. 21. 10/24/2023 D3 71 of 196

14 can expect to have a $1,614 annual savings relative to adoption of the same electrification 1 technologies under the current rate structure. For PG&E and SDG&E these savings would be 2 $1,771 and $1,929, respectively. 3
4 Figure I-5
SCE Example: Non-CARE Inland Income Bracket 3 Customer Energy Burden Comparison

5 d) Promoting Bill Stability and Maintaining Strong TOU Price Signals. 6 With their reliance almost entirely on volumetric rates for recovering the costs of 7 providing service to residential customers, the Joint IOUs’ current residential rate structures have 8 an inherent challenge of causing month-to-month bill volatility.17 But the Joint IOUs’ proposal, 9

17 This is particularly true if those rate schedules include tiered rates. With an inclining-block tiered rate structure, an increase in a customer’s summer usage from June to July due to hotter July temperatures

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15 by collecting a significant portion of residential revenue in fixed charges that do not vary by 1 month, will reduce this volatility. With lower volumetric rates, a customer’s bill increases from 2 one month to another due to a significant increase in usage (e.g., home cooling due to an extreme 3 weather event) will be much smaller. Similarly, the customer’s bill decreases from one month to 4 another due to a decrease in usage will be smaller as well. Thus, the Joint IOUs’ proposals will 5 lead to more stable bills as a result of collecting a greater portion of fixed costs in fixed charges 6 unaffected by usage swings. 7
The Joint IOUs’ proposals are designed to implement IGFCs in some way on all of their 8 residential rate schedules, including their TOU rates. While under the Joint IOU proposals, as 9 detailed in each IOU’s individual Rate Design Exhibits, average volumetric rates are 10 dramatically reduced over their current levels, robust differentials will remain between TOU 11 periods. This will continue to incentivize customers to shift load out of critical, higher-price 12 hours of the day through demand response, technology adoption such as battery storage, or other 13 energy efficiency efforts. 14

2. The Joint IOUs’ Proposals Will Apply to All Residential Rate Schedules 15 If the IGFC is applied unevenly, where default rate schedules have an IGFC while 16 existing electrification rates do not, it would likely lead to rate self-selection that would 17 compromise the benefits achieved by the IGFC. Specifically, it would set up an arbitrage 18 opportunity through which customers who would be adversely impacted on schedules with 19 IGFCs could, instead, switch to one of the optional rates without an IGFC to avoid paying their 20 share of fixed costs. This would undercut the IGFC’s goals of equity and rate affordability, 21 especially for the most economically disadvantaged customers. 22 It is still permissible under AB 205 for the Commission to adopt different sets of income-23 graduated fixed charges for different residential rates. For example, the Commission might 24

can easily lead to disproportionately larger increases in the customer’s bill due to usage moving from a lower-price tier to a higher-priced one.
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16 approve somewhat higher IGFCs for the current electrification rates that already have some level 1 of fixed charge, than it adopts for other more standard rates because doing so would better 2 support the state’s decarbonization efforts. Therefore, the Joint IOUs’ proposals recommend that 3 all of their residential rates, including TOU rates, must have at least the same IGFC as the default 4 rates. The IGFCs will not adversely affect the price signals customers see, to inform them of the 5 varying costs during different periods of the day – they merely reduce the total revenue collected 6 from volumetric charges but can still be designed to maintain cent per kWh price differentials 7 between peak and off-peak periods that appropriately reflect underlying marginal costs and 8 continue to incentivize load shifting. 9

3. The Joint IOUs’ Proposals Are Consistent with Rate Design Principles. 10 While the revisions to the CPUC’s rate design principles (RDPs) had not been finalized at 11 the time this testimony was written,18 the draft of such revisions (with which the Joint IOUs 12 largely agree) affirm that significant changes in residential rate design are necessary, including to 13 reflect the addition of decarbonization through electrification as a major state policy goal for 14 achieving GHG reductions. The Joint IOUs intend to provide a full assessment of all proposals, 15 according to the final rate design principles, in Reply Testimony, but some changes to the RDPs 16 appear to already be certain enough to warrant comment now. 17 In particular, the change in RDP 4 to “Rates should encourage economically efficient (i) 18 use of energy, (ii) reduction of GHG emissions, and (iii) electrification”19 reflects a major shift in 19 rate design priorities. In prior rate designs, the reduction of electricity use through conservation 20 and energy efficiency was prioritized regardless of whether that was environmentally 21 responsible. The percentage of non-GHG emitting resources in the current statewide generation 22

18 On March 17, 2023, the assigned ALJ issued the Proposed Decision Adopting Electric Rate Design Principles and Demand Flexibility Design Principles (RDP Proposed Decision). The Proposed Decision included Attachment A, the Electric Rate Design Principles, Demand Flexibility Design Principles, and explanations for each.
19 RDP Proposed Decision, Attachment A, p. 2.Q.
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17 mix is much higher now, over 52%20 non-GHG emitting (i.e., carbon free) resources, compared 1 to 2011 when the current rate design principles were adopted. The state’s renewables policies 2 ensure that this trend will only continue. The driving force of state policy now points to 3 increased electric use through beneficial electric technologies (like EVs, heat pump space 4 cooling and heating, heat pump water heaters, induction ranges, and battery storage). This shift 5 has major ramifications for rate design by shifting its emphasis from the efficient use and 6 conservation of electricity to the efficient increased use of electricity in order to facilitate the 7 energy transition, while improving affordability of household energy consumption. The 8 proposed revision to the language in RDP 2, (“Rates should be based on marginal cost”)21) and 9 RDP 8 (“Rates should be technology-neutral and avoid cross-subsidies, unless the cross-10 subsidies appropriately support explicit state policy goals”)22 indicate that rates should provide 11 volumetric price signals as close to marginal costs as possible, while balancing other rate design 12 principles. Today’s rates feature volumetric price signals that are significantly higher than the 13 marginal costs in low-cost hours, as shown in the Rate Design chapter (Table II-4), which can 14 discourage the voluntary adoption of electrification technologies. The shift towards more fixed 15 cost recovery through fixed charges can bring residential rates to a point where technology-16 neutral rates that avoid or minimize cross-subsidization are achievable. 17 Additionally, just as advancements in technology and policy have led the reformed rate 18 design principles expected in this proceeding, updated principles should include the ability to 19 adapt to continuous changes as California’s landscape evolves. 20

20 California Energy Commission, Annual Power Content labels for 2021 available at https://www.energy.ca.gov/programs-and-topics/programs/power-source-disclosure/power- content-label/annual-power-content-2.
21 RDP Proposed Decision, Attachment A, p. 1.Q.
22 RDP Proposed Decision, pp. 2-3.Q.
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18 C. The Joint IOUs’ Proposals Should be Adopted as Soon as Possible. 1 California’s current residential rate design must be updated as soon as possible. This is 2 because the Joint IOUs’ lowest income customers are experiencing affordability challenges 3 today through volumetric electricity rates. Approximately two-thirds of costs serving residential 4 customers that are collected in volumetric rates today do not fluctuate as customer usage 5 increases or decreases, resulting in volumetric rates that are significantly higher than the 6 marginal cost to serve customers. The result is a regressive structure where lower-income 7 households contribute a much larger share of their income than higher income customers. As the 8 Joint IOUs continue to build and maintain the necessary infrastructure to green the grid, 9 collecting these fixed costs through volumetric rates will further exacerbate these affordability 10 and equity issues. 11
Further, high volumetric rates increase the cost of electrifying customer homes and 12 vehicles, a critical change that must occur for the state to meet its aggressive, but necessary, 13 climate mandates. As stated above, the State must decarbonize faster than it has over the past 14 decade, but the current outdated default rate structure is an impediment to achieving these goals. 15 Due to these reasons, the Joint IOU proposals should be implemented as soon as practicable 16 through the Joint IOUs’ implementation plan described in Chapter 4. 17 D. Income Verification Should Be Performed By State Agencies and Not The IOUs 18 The Joint IOUs have long administered programs like CARE and FERA, which provide 19 discounts to low-income customers. However, these are opt-in programs where eligible 20 customers voluntarily give the IOUs information regarding income. This income is not verified 21 but is subject to a potential audit. 22
The IGFC will be fundamentally different. The Joint IOUs are not aware of any other 23 fixed charge that is income differentiated based on all levels of household income and that is 24 mandatory for all. Consequently, millions of households will need to be categorized into fixed 25 charge income brackets based on household income and verified to ensure accuracy and billing 26 10/24/2023 D3 76 of 196

19 integrity. Successful implementation will require customer trust and assurance of confidentiality 1 in the process. 2
As discussed more fully in Chapter 3 (Income Verification), a state agency, potentially 3 with the assistance of a Third-Party administrator, would be best situated to take on the complex 4 income verification and bracket assignment work that will be necessary to implement the IGFC. 5 The Joint IOUs believe the Commission is the state agency likely in the best position to take on 6 this role, overseeing a Third Party. The Commission has experience in a somewhat similar role 7 in relation to the California LifeLine program, for which a “TPA” (Third-Party administrator) 8 has performed income verification/eligibility certification under the Commission’s supervision.23 9 A state agency like the Commission is in a much better position to access the financial data 10 necessary for Income Bracket placement, as well as to manage ongoing updates, customer 11 appeals, and other implementation issues. The Commission is also well-placed to perform this 12 role because it is giving the Joint IOUs direction in this proceeding and AB 205 specifically tasks 13 the Commission with authorizing the residential income-graduated fixed charge. 14 In contrast, the Joint IOUs are not well-situated to perform income verification. 15 Verifying the state’s ~12 million electricity customers served by the Joint IOUs would require a 16 significant and costly business expansion for each IOU to separately build out new capabilities. 17 Building processes and adding resources to perform a wholly new set of functions as well 18 handling any customer appeals relating to income level placement, would impose substantial 19 administrative burden and cost on the Joint IOUs, ultimately paid by our customers. 20 Moreover, income verification also implicates cybersecurity, customer privacy and 21 consumer protection issues. California law includes significant privacy protections,24 including 22

23 See D.05-04-026, p. 26 (concluding that income certification/verification for Lifeline Program should be performed by a TPA “under the direction of a state agency, namely the Commission”). 24 See, e.g., Civ. Code 1798.1 (“the right to privacy is a personal and fundamental right protected by Section 1 of Article I of the Constitution of California and by the United States Constitution and [] all individuals have a right of privacy in information pertaining to them).” 10/24/2023 D3 77 of 196

20 through the California Consumer Privacy Act of 2018 (CCPA).25 The Commission also has 1 endorsed privacy protections in its decisions.26 Privacy and data protection concerns have 2 increased among the public at large given large data breaches in recent years, among other 3 events. Additionally, processes will need to be established to access various sources of income 4 data among state agencies, to maximize reliable household income data for these purposes. 5 In light of these complexities and challenges for income verification, a state agency 6 (potentially with Third Party support) leveraging and building upon existing capabilities and 7 experience will be best positioned to effectively manage needed income verification for the 8 IGFC. The Joint IOUs thus propose a framework modeled on the structure of the 9 telecommunications LifeLine program’s Third Party administration with CPUC supervision, so 10 that income verification is performed through a state agency, without undermining rate 11 affordability. Additionally, if authorized by legislation, it would be most appropriate for income 12 verification activities to be funded by the state rather than electricity customers, consistent with 13 funding provided for other societally beneficial activities administered by state agencies. 14 E. Robust Marketing, Education, and Outreach Will be Required 15 The IGFC rate structure will substantially shift how residential customers pay for 16 electricity service in the future. A robust ME&O plan will be required to provide customers with 17 early awareness of the change, help customers understand bill impacts, and highlight why reform 18 is needed. The Joint IOUs will use various customer communication channels to form a holistic, 19 integrated education and outreach campaign to support IGFC implementation. Channels 20 envisioned include direct-to-customer messaging, broad customer outreach, IOU-owned and paid 21

25 The CCPA (Civ. Code §§ 1798.100–1798.199.100) provides for various rights, including the rights to: know about personally identifiable information (PII) a business collects and how it is used and shared; delete personal information (with some exceptions); opt-out of the sale or sharing of personal information; correct inaccurate personal information; and limit the use and disclosure of sensitive personal information.
26 See, e.g., D.11-07-056, at p. 130, Finding of Fact 1 (FOF) (endorsing Fair Information Practices (FIPs) including “data minimization” principle).
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21 channels, and community outreach. The Joint IOUs’ education materials will be informed by 1 customer research. We expect it will focus on how the IGFC will make rates more equitable 2 overall while supporting the State’s goal of making beneficial electrification technologies more 3 affordable, by lowering volumetric rates. The Joint IOUs recognize additional customer input 4 will be needed to properly meet customer education needs. The Joint IOUs plan to conduct 5 additional research in 2023 to continue to learn from customers the preferred and most effective 6 messaging and approach to IGFC education. The Joint IOUs’ detailed ME&O plan is discussed 7 in more detail in Chapter 5 included in this testimony. 8 F. Conclusion 9
While California’s energy environment has changed rapidly in recent decades, its 10 residential rate design continues to collect the majority of fixed and variable utility costs through 11 volumetric rates. As a result, electricity rates are substantially higher than the marginal cost of 12 providing that electricity. The Joint IOUs’ proposals modernize California’s residential rate 13 structure by providing a more affordable and equitable path forward. The chapters that follow 14 explain how the Joint IOUs’ proposals accomplish these goals and we respectfully encourage the 15 Commission to accept these proposals to ensure the transition to income-graduated residential 16 fixed charges is as smooth and successful as possible.17 10/24/2023 D3 79 of 196

22 II. 1
RATE DESIGN 2
A. Introduction 3

1. Summary of Proposals 4
The Joint IOUs propose to add Income Graduated Fixed Charges (IGFCs) to all of their 5 residential rate schedules, with limited exceptions.27 Most of the Joint IOUs’ residential 6 schedules will receive the same, four-bracket fixed charges, with the low-income fixed charges 7 set at the household Income Brackets shown in Table I-2. For policy reasons, the IOUs’ 8 proposed fixed charge Income Brackets do not encompass all of each utility’s respective fixed 9 costs. By carving out an amount of the total fixed costs from the current artificially high 10 volumetric rates, the California Public Utilities Commission (Commission or CPUC) will make 11 significant progress to support affordability and increased bill stability. It also supports 12 decarbonization by removing the disincentive for residential customers to add beneficial electric 13 end-uses needed to meet the state’s greenhouse gas (GHG) reduction goals. 14 The Joint IOUs’ IGFC proposals are intended to maintain customer choice and improve 15 equity, while providing greater bill stability and promoting beneficial electrification. The Joint 16 IOUs’ Illustrative IGFC proposed fixed charges and rates are shown below on Tables I-2 and I-3. 17 In this proposal, the Joint IOUs are seeking approval of: 18  Fixed cost categories, which result in class average monthly28 fixed charges of: 19 o PG&E: $53/month 20

27 All residential whole-home rate schedules should have at least the same level of IGFC in order to avoid customer rate switching and IGFC avoidance through rate arbitrage. However, non-IGFC fixed charges for separately metered EV rates may be appropriate and are addressed in IOU specific Rate Design testimony exhibits.
28 Operationally, these fixed charges would be charged to customers on a dollar-per-day basis.

However, the IOUs are presenting these fixed charges on a per-month basis for reference. 10/24/2023 D3 80 of 196

23 o SDG&E: $74/month, including approval of its new proposed rate component, the 1 Electrification Incentive Adjustment (EIA) 2
o SCE: $49/month; 3
 IGFCs on the following residential rate schedules: 4 o PG&E rate schedules: E-1, E-TOU-C, E-TOU-D, EV2-A, E-ELEC 5 o SDG&E rate schedules: DR, TOU-DR1, TOU-DR2, EV-TOU-2, DR-SES, EV-6 TOU-5, TOU-DR, and TOU-ELEC 7
o SCE rate schedules: TOU-D 4-9, TOU-D 5-8, Schedule D 8  Considerations for including higher IGFCs for certain residential rate schedules that 9 currently have fixed charges: 10
o PG&E’s Schedule E-ELEC 11
o SDG&E’s Schedules EV-TOU-5 and TOU-ELEC; 12
o SCE’s Schedule TOU-D-PRIME 13
 Reduction of non-CARE average volumetric kWh rates as described in individual 14 IOU exhibits: 15
o PG&E: From $0.34/kWh to $0.22/kWh 16
o SCE: From $0.36/kWh to $0.24/kWh 17
o SDG&E: From $0.47/kWh to $0.27/kWh 18
 Elimination of the Minimum Bill. 19
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24 Table II-2
Illustrative Proposed IGFCs

Table II-3
Illustrative Summary of Impacts to Default Rates29

B. Background 1

1. Recent Rate Design Policy Issues 2
The impetus for Track A (IGFC) of this proceeding stems from Assembly Bill (AB) 205, 3 which was passed on June 29, 2022, and chaptered after being signed into law by Governor 4 Newsom on June 30, 2022. The Commission has previously considered but declined to adopt 5 fixed charges for residential customers, and instead, required the three electric IOUs to 6 implement residential minimum bills. The Joint IOUs provide a brief history of how the 7 Commission’s thinking on residential fixed charges has evolved over time and emphasize the 8

29 Status Quo rates are the model calculated counterfactual rates, not current actual rates. 10/24/2023 D3 82 of 196

25 importance of adopting IGFCs that apply equitably to all customers and meaningfully reduce 1 volumetric rates in the instant proceeding. Substantive rate reform is critical for California to 2 reach its GHG reduction and climate goals. 3
From 2013 until AB 205 was passed, the previous statute (Public Utilities Code Section 4 739.9) included a cap that limited residential fixed charges to approximately $10/month for non-5 CARE customers and $5/month for CARE customers.30 AB 205 removed this cap and required 6 the CPUC to approve a compliant IGFC structure for default residential rates by July 1, 2024.31 7 The Commission has previously considered default residential fixed charges in various 8 proceedings but the Energy Division IGFC Guidance for this proposal states that parties are not 9 bound by these prior Commission decisions.32 10
Nonetheless, as a foundation, the Joint IOUs provide a brief background of the history of 11 residential fixed charge proposals in California and the Commission’s current direction regarding 12 historical determinations about residential fixed charges. The Joint IOUs proposed fixed charges 13 approximately ten years ago in the Residential Rate Reform Rulemaking (R.) 12-06-013 14 (RROIR). While Decision (D.) 15-07-001 set a multi-year glidepath to consolidate and narrow 15 the tier differentials in effect at that time, the Commission declined to adopt a default residential 16 fixed charge, stating that it was not appropriate to adopt a fixed charge at the same time as 17 residential customers were being defaulted to time-of-use (TOU) rates.33 The Joint IOUs were 18 directed to concurrently file rate design window (RDW) applications by January 1, 2018, which 19 could include proposals for default residential fixed charges.34 D.15-07-001 additionally stated 20 that the Joint IOUs should, separately from the Residential Rate Reform OIR (R.12-06-013, 21

30 AB 327 (Reg. Sess. 2013-2014), Pub. Util. Code § 739.9(f), which also provided for an annual Consumer Price Index increase to these base capped fixed charge levels, starting in 2015. 31 AB 205 (Reg. Sess. 2021-2022).
32 Administrative Law Judge’s Ruling Providing Guidance for Phase 1 Track A Proposals and Requesting Comments on a Consulting Services Proposal (Jan. 17, 2023), Attachment 1, R.22-07- 005, Phase 1 Track A: Income-Graduated Fixed Charge Guidance Memo. 33 D.15-07-001, at p. 328, Conclusion of Law (COL) 17.
34 D.15-07-001, at p. 327, Ordering Paragraphs (OP) 9-11. 10/24/2023 D3 83 of 196

26 RROIR), “in their individual GRC Phase 2 proceedings, … work to identify customer-related 1 fixed costs for purposes of calculating a fixed charge.”35 2 Within PG&E’s 2017 GRC Phase 2,36 the Commission established a separate track 3 (Fixed Charge Track) to adopt categories of fixed costs that could be included in a residential 4 default fixed charge. The final decision in the Fixed Charge Track, D.17-09-035, adopted an 5 extremely narrow definition of what costs could be included in the default residential fixed 6 charges proposed in A.17-12-011.37 That narrow definition38 would have limited the Joint IOUs’ 7 non-CARE fixed charges to approximately $7.10/month for PG&E,39 $8.84/month for 8 SDG&E,40 and $6.68/month for SCE.41 Using such a definition today would do little to reduce 9 volumetric rates and incentivize beneficial electrification because volumetric rates would be 10 reduced by less than $0.02/kWh. 11
In 2021, the Commission adopted a final decision in PG&E’s 2020 GRC Phase 2 (A.19-12 11-019) that reversed its stance on categories of costs that may be recovered in default residential 13 fixed charges and wipes the slate clean when considering the appropriate manner for designing 14 residential fixed charges.42 In D.21-11-016, the CPUC also adopted PG&E’s new optional 15 “electrification” rate (E-ELEC), finding that: (1) “[t]he findings and conclusions in D.17-09-035 16 should be applied only in the context of A.16-06-013”43, and (2) “any future proposals for a 17

35 Id., at p. 6.
36 A.16-06-013, Application of Pacific Gas and Electric Company to Revise its Electric Marginal Costs, Revenue Allocation and Rate Design.
37 Administrative Law Judge’s Ruling Consolidating Proceedings (Jan. 25, 2018), consolidated A.17- 12-011, A.17-12-012, and A.17-12-013.
38 D.17-09-035 would have limited costs recovered in a fixed charge to certain marginal customer access costs using the “minimum cost approach”, which includes costs for only the “smallest” type customer. See, D.17-09-035, at p.33.
39 See, PG&E Rate Design Window 2018 Supplemental Testimony, Fixed Charge Proposal in Phase III, A.17-12-012, at p. 1-4.
40 See, SDG&E Prepared Supplemental Testimony of Jeff P. Stein, A.17-12-013, at p. JS-3. 41 See, SCE Amended Supplemental Testimony on Impact of Federal Tax Legislation on Proposed Rates and Fixed Charges, A.17-12-011, at p. 2.
42 D.21-11-016, at p. 113.
43 D.21-11-016, at p. 165, COL 32.
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27 default residential fixed charge or optional residential fixed charge (as in this case) should be 1 able to proceed without the need to comply with cost category and EPMC [Equal Percent of 2 Marginal Cost] determinations made in a since-closed proceeding that failed to make a 3 determination concerning a residential fixed charge on the merits.”44 Additionally, it is worth 4 noting that the Commission determined the adopted settlement on PG&E’s new E-ELEC 5 (“Electric Home”) rate, which included a residential fixed charge, was “intended to further state 6 policy goals related to decarbonization and therefore has a particular policy purpose that may 7 justify any dissonance with previous Commission decisions regarding the application of EPMC 8 to residential fixed charges.”45 9
With these findings in mind, there is no reason to limit fixed charges to a certain level or 10 hold to prior precedent. While parties may look to previous Commission decisions for reference 11 and historical context, party proposals that cite to D.17-09-035 as a reason to limit fixed charges 12 to a certain level should be dismissed, as the Commission has stated that D.17-09-035 does not 13 hold precedential value outside of A.16-06-013.46 Basing IGFC proposals on D.17-09-035 14 would make little sense in this context anyway, as the average IGFC must be large enough to 15 result in a sufficiently lower volumetric energy rate, and D.17-09-035 would limit volumetric 16 rate reduction to approximately $0.02/kWh. 17
It is important that an IGFC floor apply to all customers. Application of the IGFC to all 18 residential rates, including optional “electrification rates” currently offered by each large IOU, 19 will ensure fair treatment for all customer types and provide equal incentive for all customers to 20 electrify. If the IGFC were instead applied selectively, where some residential rate schedules 21 would have a fixed charge while others did not, this would provide an opportunity for customers 22 who would be adversely impacted on schedules with IGFCs to instead take service on one of the 23 optional rates without an IGFC, to avoid paying the IGFC. 24

44 Id., at p. 114.
45 D.21-11-016, at p. 114.
46 Id.
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28 It is still permissible under AB 205 for the Commission to adopt different sets of IGFC’s 1 for different residential rates. For example, the Commission might approve somewhat higher 2 IGFCs for PG&E’s Schedule E-ELEC, SCE’s TOU-D-PRIME, or SDG&E’s EV-TOU-5 and 3 TOU-ELEC rates than it adopts for other more standard rates, because doing so would better 4 support the state’s decarbonization efforts. Therefore, the Joint IOUs’ proposals recommend that 5 all residential rates, including optional rates, must have at least the same minimum IGFC Income 6 Brackets as the default rates. 7
The Commission should adopt appropriate fixed charges for all residential customers, and 8 not delay implementing an IGFC for certain rate schedules, because doing so would result in a 9 loophole that could allow higher income customers to receive a lower fixed charge if they mass 10 migrate to rates with delayed (or no) IGFCs. Although simultaneous implementation across rates 11 might take more up-front time, it avoids the pitfalls of mass voluntary migration to the lowest 12 possible fixed charge. 13

2. Next 10 Research on Potential Fixed Charges 14
Academic research by Next 10 Research and the Energy Institute at the UC Berkeley 15 Haas School of Business (Next 10/Berkeley Haas) played a key role in inspiring the conceptual 16 development of AB 205. Specifically, two Next 10/Berkeley Haas reports released in 2021 and 17 2022, detail concerns about the inequity of the current residential rate structure. These reports 18 suggest several methods of reform that would: (1) improve customer equity by making rates 19 more progressive, and (2) more closely align volumetric rates with marginal costs, which would 20 serve to incent widespread adoption of beneficial electrification technologies needed to achieve 21 decarbonization that meets state climate and GHG reduction goals. The Joint IOUs describe 22 these two reports in detail below. 23
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29 On February 23, 2021, Next 10/Berkeley Haas released a report titled “Designing 1 Electricity Rates for An Equitable Energy Transition” (2021 Report).47 This report used 2 historical data from the Joint IOUs to show that the price of electricity in the Joint IOUs’ service 3 territories is two to three times higher than the actual cost to produce and distribute the electricity 4 provided, and this results in electricity rates that disproportionately harm lower income 5 electricity customers.48 6
The 2021 Report opines that recovery of fixed costs within the volumetric charge is 7 “quite regressive” and suggested options for reducing the volumetric rate, including non-income 8 differentiated fixed charges or shifting cost recovery of programs and policies to the state budget. 9 It acknowledges that even a non-income differentiated fixed charge would bring significant 10 efficiency benefits.49 However, given potential concerns with both approaches, the 2021 Report 11 recommends a progressive fixed charge structure for residential customers.50 The 2021 Report 12 determined that “[a]n economically efficient volumetric price will recover some amount of 13 revenue, but it will be substantially less than the total revenue requirement for the California 14 IOUs.”51 It also considered what electricity rates might look like if their structure were as 15 progressive as California's income tax and sales taxes, and recommended structures in which 16 low-income customers would not be made worse off by rate reform. It further recommended that 17 the state, not the utilities, be the income verifying entity, as the state already has income tax 18 information. The 2021 Report also acknowledged that the utilities do not have the infrastructure 19

47 Next 10 and Energy Institute at Haas, Designing Electricity Rates for An Equitable Energy Transition (hereinafter Next 10, 2021 Report), (Feb. 23, 2021), available at https://www.next10.org/sites/default/files/2021-02/Next10-electricity-rates-v2.pdf . 48 Next 10, 2021 Report, at p. 4.
49 Next 10, 2021 Report, at p. 3. While the report also expresses concern that a non-income differentiated fixed charge would also be regressive, even in a pre-AB 205 context any fixed charge implemented by the IOUs would at least include income differentiation through the existing CARE and FERA programs.
50 Next 10, 2021 Report, at pp. 30-34.
51 Next 10, 2021 Report, at p. 35.
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30 in place to verify incomes of all residential customers and that any utility-run income-1 verification system without direct cooperation from other state agencies would be problematic.52 2 The 2021 Report discussed a theoretical structure, stating that the dollar amount of a 3 uniform fixed charge necessary to fully eliminate the cost recovery gap (if all account holders 4 were charged the same monthly fee, based on 2019 rates), would be $74.02 for PG&E, $58.80 5 for SCE, and $70.07 for SDG&E.53 Rates have increased since 2019, so the Report’s monthly 6 figures would have been higher had they been based on 2023 effective rates. Figure II-6 below 7 shows theoretical 2019 fixed charges for PG&E if the structure were as progressive as income 8 tax or sales tax.54 Under the 2021 Report's illustrative structure, households making greater than 9 $150,000 annually would be required to pay fixed charges of $150 per month or higher. 10 11 Figure II-6
2021 Next 10 Report Theoretical Fixed Charges - PG&E

12 52 Next 10, 2021 Report., at p. 38.
53 Id., at p. 40.
54 As stated in the Next 10/Berkeley paper, although sales tax applies equally to purchases made by customers of any income level, wealthier customers typically pay more sales tax because they make more purchases.
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31 On September 22, 2022, Next 10/Berkeley Haas released a follow-on report titled 1 “Paying for Electricity in California: How Residential Rate Design Impacts Equity and 2 Electrification” (2022 Report).55 This second report, which built on the 2021 Report, and 3 continued to use historical IOU data determined that the costs of programs and policies that go 4 beyond the cost of producing and distributing electricity are now the main driver of retail 5 electricity price increases. These added costs, which drive up the price per unit of volumetric 6 energy, threaten the state’s climate goals by disincentivizing electrification of buildings and 7 vehicles. In other words, separating out fixed costs from the currently combined, artificially high 8 volumetric rate, and instead recovering them in a separate fixed charge line item removes a 9 disincentive to electrification by reducing customers’ volumetric electric rate component. The 10 2022 Report also explored in detail how these higher costs disproportionately affect lower-11 income households, as higher energy bills in a lower-income household are a higher percent of 12 total income. Next 10/Berkeley Haas calculated what they refer to as “residual cost burden,” or 13 the difference between the amount the customer pays on their bill and the incremental cost to the 14 utility of providing that household with power.56 The 2022 Report concluded that recovering 15 this residual cost burden in volumetric rates raises the annual operating cost of electrification 16 technologies, referred to as the “electrification cost premium.” The current structure of 17 recovering non-incremental costs in higher retail electricity rates significantly increases 18 operating costs of EVs and electric heating.57 19
Both the 2021 and 2022 Reports were instrumental in conceptualizing how an IGFC 20 might be envisioned for California. The influence of Next 10/Berkeley Haas’ work is apparent 21 in the text of AB 205, which requires no fewer than three income thresholds, so that a low-22

55 Next 10, Paying for Electricity in California.
56 Id., at p. 4.
57 Id., at pp. 19-21.
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32 income ratepayer in each baseline territory would realize a lower average monthly bill without 1 making any changes to their usage.58 2
While these two Next 10/Berkeley Reports helped conceptually spur adoption of an IGFC 3 approach in AB 205, there are many practical operational issues that require consideration when 4 actually designing and implementing an IGFC that complies with the conceptual guidance in AB 5 205. The Joint IOUs’ proposal maintains compatibility with current operational and data 6 capabilities, and achieves an equitable, reasonably progressive structure that improves 7 affordability for low-income customers and incentivizes electrification. 8

3. The Joint IOUs’ Proposals Align with Modernized Rate Design Principles 9 The Commission is in the process of modernizing the Rate Design Principles (RDPs) in 10 Track B of this proceeding.59 A Proposed Decision was issued on March 17, 2023, with a final 11 decision targeted for the CPUC’s April 27, 2023, business meeting. Therefore, the current 12 procedural schedule for submittal of Track A IGFC Opening Testimony on April 7 cannot 13 precisely reflect the Final Decision on modernized RDPs. Nonetheless, the Proposed Decision 14 for modernized RDPs provides general directional guidance that can help inform parties’ initial 15 IGFC proposals. First, the Proposed Decision indicates that parties should not prioritize energy 16 efficiency and conservation over beneficial electrification, consistent with AB 205.60 The Joint 17 IOUs’ proposals seek to reflect, as much as possible, key elements of the recent Proposed 18 Decision recommending modernized RDPs, while aligning with AB 205’s requirements. 19 Although prior Commission decisions had expressed concern that fixed charges would 20 likely not encourage additional conservation,61 the average kWh rate levels resulting from the 21 Joint IOUs’ proposed IGFCs (approximately 22-27 cents/kWh) are similar to the volumetric rate 22 levels at the time of Mass TOU Default, when the Commission concluded that the impact of a 23

58 Pub. Util. Code § 739.9(e)(1).
59 Rulemaking 22-07-005 Assigned Commissioner’s Scoping Memo and Ruling, p. 4. 60 PD, p. 14.
61 D.15-07-001, at p. 214.
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33 fixed charge on conservation is likely to be small.62 Under the recent Proposed Decision, the 1 term conservation is no longer used; rather the proposed revised RDP 4 states that “[r]ates should 2 encourage economically efficient (i) use of energy, (ii) reduction of greenhouse gas emissions, 3 and (iii) electrification.” In addition, RDP 5 states “rates should encourage customer behaviors 4 that improve electric system reliability in an economically efficient manner” (which seem to 5 effectively include conservation). Thus, the CPUC will have to balance the clear goals of 6 beneficial electrification from AB 205 with the other elements of the RDPs, while it decides how 7 to make future rates compliant with AB 205 so as not to inhibit beneficial electrification.63 8 The recent Proposed Decision also emphasizes that “[r]ates should avoid cross subsidies 9 that do not transparently and appropriately support explicit state policy goals. Similarly, the 10 recent Proposed Decision’s RDP 9 would provide that “[r]ate design should not be technology-11 specific and should avoid creating unintended cost-shifts.” The Joint IOUs’ proposed IGFCs 12 will also provide customers with bill stability through reduced month-to-month bill volatility, to 13 help customers manage their bills, as well as to encourage economically efficient decision 14 making 15
Additionally, the Joint IOUs’ proposed IGFCs take into account the Proposed Decision’s 16 RDP 7, on customer understandability. The four household Income Bracket approach balances 17 customer understandability with a meaningful fixed charge to encourage beneficial 18 electrification. If the CPUC’s final decision on RDPs were to differ significantly from the 19 Proposed Decision, the Joint IOUs reserve the right to consider whether revised Joint IOU IGFC 20 proposal might be warranted, and work with the Commission and other parties on how best to 21 accomplish that, if needed. 22

62 Id.
63 Track B of this proceeding is considering changes to the RDPs. 10/24/2023 D3 91 of 196

34 C. Basis for the Average IGFC Level 1
The sections below describe in detail the multi-step process the Joint IOUs utilized in 2 designing proposed IGFCs. In sum, the first step is to determine the overall proportion of 3 residential revenue requirements that should be collected through the fixed charge instead of 4 volumetric rates. Second, once the average fixed charge Income Bracket has been determined, it 5 must be established how the volumetric rate design is impacted. Then, after volumetric rate 6 levels are calculated, the third and last step is to determine what discount or surcharge levels are 7 appropriate to result in a graduated, progressive fixed charge level for each successive income 8 “bracket.” The same generic methodology was used by each of the Joint IOUs to develop each 9 IOU’s average fixed charge and average volumetric rate. 10

1. Methodology for Determining Average Fixed Charge Level 11 The top priority and guiding principle of the fixed charge is to bring volumetric rates 12 closer to cost basis. As seen in Table II-4 below, today’s default utility rates64 are far higher than 13 marginal costs as measured by both :(1) recent PG&E GRC Phase II marginal costs, and (2) the 14 CPUC’s 2022 version of the avoided cost calculator (ACC). This disconnect has the 15 consequence of discouraging additional beneficial use of electricity, both for electrification but 16 also for home health and safety. 17

64 AB 205 mandated the CPUC “shall” authorize IGFCs at least for the IOUs’ “default residential rate” and “may” adopt IGFCs for other rate schedules. For PG&E, the default residential rate is E-TOU-C, for SCE the default rate is TOU-D 4-9, and SDG&E’s default residential rate is TOU-DR-1. 10/24/2023 D3 92 of 196

35 Table II-4
PG&E Default Rates Compared to Marginal Cost Metrics

*65
**66
The Next 10/Berkeley research suggested that a fixed charge be implemented at a level 1 such that volumetric rates are approximately aligned with marginal costs.67 As shown in Table 2 II-4, achieving this would require average fixed charges over $100 for non-CARE customers, 3 varying by what definition of marginal costs is used and what marginal cost categories are 4 defined as “fixed costs.” While the Joint IOUs have opted to propose fixed charges somewhat 5 lower than these benchmarks, the values required to reduce volumetric rates to marginal cost 6 form at least one “bookend” to illustrate the highest level of the average fixed charge possible 7 (which would result in the greatest reduction in the volumetric charge and thus best support 8 electrification goals) and encouraging economically efficient use of energy. 9 Another way to evaluate what could be considered the upper end of the range of possible 10 average fixed charges would be to determine which portion of utility revenue requirements do 11 not vary with usage and what fixed charge level would be required to collect those costs, leaving 12

65 Includes all 2022 Avoided Cost Calculator Categories – Energy, Cap and Trade, GHG Adder/Rebalancing, Generation Capacity, Distribution Capacity, Transmission Capacity, Ancillary Services, and Methane Leakage.
66 Includes all PG&E Marginal Costs used in cost-of-service study (MEC, MGCC, MDCC (Primary, New Business, Secondary)). Excludes transmission marginal cost. MDCC values presented on $/kWh basis for comparison purposes only.
67 Next 10 2022 Report: at p. 28.
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36 only costs that do vary with usage still collected in the volumetric rate. Table II-5 below shows, 1 for non-CARE customers, what fixed charge level would collect the entirety of the fixed cost 2 revenue requirement categories identified in the Public Tool,68 by utility. 3

68 The final version of the Public Tool was made available for public use on March 23, 2023. 10/24/2023 D3 94 of 196

37 Table II-5
Illustrative Fixed Cost Revenue Requirement Categories in the Public Tool ($/month charge) – Residential Non-CARE Customers

*69
**70
***71
****72
Of these, the Joint IOUs include certain categories in their respective proposed IGFCs. In 1 the textual discussion further below, we provide additional detail on why a given category of 2 fixed costs would be appropriate to collect through the IGFC, or not. Also, Table II-6 below 3 provides a summary of the proposed components in the cumulative fixed charges and cumulative 4 volumetric rate reduction that results from each component. 5

69 The value of $7.88/mo. represents a settled marginal cost value used for revenue allocation purposes in SCE’s 2021 GRC Phase 2 Proceeding. SCE’s filed marginal customer costs based on the RECC methodology is $10.94/month.
70 Includes Distribution Primary New Business for PG&E. 71 Varies by IOU but includes all NBCs other than PPP and PCIA listed on Revenue Allocation Tabs. 72 For PG&E, based on bundled customer-months billing determinant. For SCE and SDG&E, based on the Public Tool calculated total generation revenue on “Rate Design Detail” tab, Cell F380, divided by total residential customer count, then ratioed to calculate non-marginal generation costs. 10/24/2023 D3 95 of 196

38 Table II-6
Revenue Requirement Categories Underlying the Joint IOUs’ Proposed Fixed Charges and Resulting Reductions in the Volumetric Rate Component73

Marginal Customer Access Costs (MCAC): MCACs represent the incremental costs of 1 connecting an additional (i.e., marginal) customer to the grid that are not driven by volumetric 2 energy usage or demand. The two cost components of MCACs are: 1) the marginal customer 3 equipment costs (MCEC) consisting of final line transformer, service line drop, and meter costs, 4 and 2) the ongoing and variable Revenue Cycle Service (RCS) costs associated with keeping 5 customers connected to the grid, such as customer billing, meter reading, and credit and 6 collections. This category should be collected through a fixed charge. 7 Marginal Distribution Demand Costs: Marginal distribution demand costs measure the 8 cost of serving an additional unit of customer kilowatt (kW) demand on the electric distribution 9 system. Distribution demand costs reflect the costs to deliver electricity from the substation to 10 the customer’s premise based on the customer’s maximum kW demand and consist of substation 11 and circuit facilities costs and applicable operations and maintenance (O&M) costs. Each utility 12

73 Table values calculated by dividing associated revenue requirements by customer-months and kWh billing determinants used in the Public Tool. Totals differ from class average fixed charge due to effects of the CARE discount.
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39 defines these marginal costs slightly differently, and we therefore defer additional discussion to 1 each IOUs’ separate rate design exhibit. 2
Non-Marginal Distribution Costs: The Joint IOUs propose to collect all non-marginal 3 distribution costs through the fixed charge, as these do not vary with the volume of electricity 4 consumed. There are many costs recovered through distribution rates that are not directly linked 5 to marginal costs. The Joint IOUs recover the costs of wildfire mitigation and vegetation 6 management, reliability improvements, safety and risk management distribution costs, ongoing 7 distribution operations and maintenance, many regulatory balancing accounts, and various 8 programs and policy mandates through its distribution rates. These costs are not driven by a 9 customer’s usage, and therefore should be collected through the IGFC. 10 Transmission and Reliability Services: Transmission costs and retail rate design fall 11 under the jurisdiction of the Federal Energy Regulatory Commission (FERC), and therefore do 12 not fall within the scope of a CPUC proceeding setting the Joint IOUs’ retail IGFC rate 13 component. Conceptually, many of the costs to operate and maintain the transmission system do 14 not vary with usage, and in theory could be considered appropriate for inclusion as a fixed 15 charge. However, due to the jurisdictional boundary in this CPUC proceeding, the Joint IOUs 16 are not proposing that the IGFC be authorized to collect any transmission costs. 17 Public Purpose Programs (PPP): The PPP charge funds essential programs such as 18 energy efficiency and CARE discounts that have no relationship to the volume of electricity 19 consumed by customers and are explicitly authorized by AB 205 to be collected through a fixed 20 charge. These critical public policy programs should be funded through the intentionally 21 progressive mechanism of the income-based fixed charge because continuing to include them in 22 a flat volumetric rate can have regressive effects contrary to equity goals. In the Public Tool, 23 this category is split into three subcategories (Non-CARE Exempt, Self-Generation Incentive 24 Program (SGIP), and Residential CARE contribution). All three subcategories are appropriately 25 recovered through the IGFC. 26
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40 Other Non-bypassable Charges: All non-bypassable charges (NBCs) would 1 theoretically be better collected through an IGFC than volumetric rates, given that the underlying 2 revenue requirements do not vary with customer usage. However, as discussed in the Joint 3 IOUs’ Briefs on AB 205 statutory interpretation, the Wildfire Fund Charge, Competition 4 Transition Charge, and prospective charges for continued operation of Diablo Canyon likely 5 cannot be collected through the IGFC due to statutory restrictions. Further, there are other 6 charges that lack such statutory restrictions, but nonetheless have contractual restrictions, 7 including the Wildfire Hardening Charge and the Recovery Bond Charge/Credit. Remaining 8 non-bypassable charges that should be collected through a fixed charge are the current Nuclear 9 Decommissioning Charge (ND) and New System Generation Charge (NSGC)/Local Generation 10 Charge (LGC). The ND funds the decommissioning of nuclear power plants that have already 11 been built; changes in customer usage will have no impact on the level of these costs. Likewise, 12 NSGC/LGC funds essential generation reliability resources procured per state policy 13 requirements. 14
Marginal Energy Costs (MEC): MECs are those costs necessary to procure a marginal 15 amount of energy; MECs reflect a combination of wholesale market prices and costs of meeting 16 renewable portfolio standard requirements. Since MECs are tied directly to wholesale electricity 17 market prices, these costs are appropriately recovered through volumetric rates. 18 Marginal Generation Capacity Costs (MGCC): MGCCs reflect changes in generation 19 capacity costs that are associated with usage coincident with peak demand. These generation 20 capacity costs do not include the cost of energy itself, as such costs are instead captured by the 21 MEC calculation. Instead, MGCCs look at the cost of the physical capability to generate 22 electricity, which usually consists of costs to construct a new power plant and its associated 23 operation and maintenance costs. While MGCCs do not strictly vary according to volumetric 24 usage, they are more appropriately recovered through time-varying rate designs. How this aspect 25 of rate design should be altered is being appropriately addressed in other phases of this 26 proceeding. 27
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41 Power Charge Indifference Amount (PCIA): The PCIA is a charge to ensure that both 1 IOU customers and those who have left IOU service to purchase electricity from other providers 2 pay for the above market costs for electric generation resources that were procured by the IOU 3 on their behalf. “Above market” refers to the difference between what the utility pays for 4 electric generation and current market prices for similar resources. While traditionally 5 denominated as a $/kWh charge, the underlying costs recovered through the PCIA do not vary 6 with volumetric usage. Much of PCIA reflects early investments in high cost GHG free 7 resources to grow the clean energy industry, not to meet least cost procurement needs. As such, 8 it could be argued that these costs would be better recovered through a progressive cost recovery 9 mechanism, such as the IGFC. Nonetheless, the Joint IOUs are not proposing to recover PCIA 10 costs through the IGFC at this time. 11
Non-Marginal Generation Costs: This value is residually calculated by subtracting 12 MEC, MGCC, and PCIA from the total generation revenue requirement, and reflects the degree 13 to which present procurement costs exceed the marginal costs estimated in the most recent GRC. 14 The Joint IOUs do not propose to collect these costs through the IGFC. 15 Electrification Incentive Adjustment: To reach a volumetric rate that is more 16 accurately cost-based and more effectively incentivizes electrification and the transition to 17 carbon-neutral energy, SDG&E is proposing a new rate component, the Electrification Incentive 18 Adjustment (EIA) rate. Because PG&E’s and SCE’s proposed fixed charges result in an average 19 volumetric rate that is $0.25/kWh or lower, PG&E and SCE are not proposing an EIA rate 20 component that would act as a policy adder to the fixed charge. The purpose of this rate 21 component for SDG&E is to collect more revenue in a fixed charge and in real time return that 22 same revenue through a credit to the volumetric rates. The concept is similar to the Conservation 23 Incentive Adjustment/Total Rate Adjustment Component (CIA/TRAC), which functionally 24 collects more revenues from higher usage customers and returns that revenue in real time as a 25 discount to Tier 1 (baseline) rates based on a specified differential. The EIA charge would 26 collect more funding through a $/month fixed charge and reduce $/kWh rates than would 27 10/24/2023 D3 99 of 196

42 otherwise be possible under the Joint IOUs’ determination of costs that should be collected from 1 the IGFC at this time. This charge is a transparent way of increasing the fixed charge to a level 2 that will allow for enough volumetric rate reduction to incentivize beneficial electrification. The 3 EIA is discussed in more detail in SDG&E’s rate design testimony (Exhibit SDGE-01). SDG&E 4 is also requesting a two-way balancing account to track this new rate component, which is also 5 discussed in Exhibit SDGE-01. 6
D. Income Graduated Fixed Charge Discount Levels 7

1. Summary 8
The Joint IOUs’ proposed IGFC structure will include four household Income Brackets 9 (or levels) at the household74 level, with the lowest two brackets consisting of CARE and FERA 10 customers. The upper Income Brackets would apply to all non-CARE/FERA customers, with 11 the highest bracket representing approximately 20-25% of the residential population, based on 12 each utility’s respective population as represented in the Public Tool. As discussed in more 13 detail in the Joint Income Verification Chapter, the Joint IOUs’ proposed Income Brackets are 14 designed to leverage existing household income data from the CARE and FERA programs and 15 utilize Federal Poverty Levels (FPL) for Income Bracket 3 (moderate-income) and Income 16 Bracket 4 (higher-income), consistent with how CARE and FERA program eligibility is 17 currently determined. The Joint IOUs are not proposing to verify customer incomes, and instead 18 use a CPUC-administered process for reasons described in the Joint Income Verification and 19 Policy Chapters. With this framework, the Joint IOUs are not required to collect household 20 income, anew, on their entire respective customer bases, but rather focus on an evolutionary 21 income verification process in the non-CARE/FERA segments. The Public Tool does not 22

74 “Household” means customers, consistent with the definition of “low-income electric and gas customers” used in Section 739.1 with respect to the CARE program, which defines such customers as those with “annual household incomes that are no greater than 200 percent of the federal poverty guideline levels.” A “household” should be defined as the persons residing in the home. Joint Utilities Opening Brief on Statutory Interpretation Questions, at p. 20; Joint Utilities Reply Brief on Statutory Interpretation Questions, at p. 11.
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43 provide income data stratified by FPL, but the ALJ Ruling Providing Additional Guidance for 1 Track A Proposals and Staff Guidance Memo on Using the E3 Fixed Charge Tool to Prepare 2 Opening Testimony75 provides guidance on how to use the Public Tool to model FPL thresholds. 3 The Public Tool provides CARE/FERA information and non-CARE/FERA customer data in 4 increments that correspond to FPL, which allows for grouping of customer populations into 5 brackets that correspond to FPL when assuming a household size of three as required by the Staff 6 Guidance Memo. The Joint IOUs’ proposals for Income Brackets thresholds are based on the 7 data in the Public Tool, and therefore, may need to be adjusted once customer incomes are 8 verified, if the percent of customers falling in one bracket produces disproportionate impacts on 9 the population in a given Income Bracket. The Joint IOUs propose the following household 10 Income Brackets: 11
 Bracket 1 – Extra Discounted Fixed Charge (applicable to a subset of the lowest 12 income CARE customers) with household income of up to 100% of Federal Poverty 13 Level. 14
 Bracket 2 – Discounted Fixed Charge (remaining CARE and FERA customers that do 15 not fall in Bracket 1). 16
 Bracket 3 – Fixed Charge for Non-CARE/FERA customers with household income 17 up to or equal to 650% of Federal Poverty Level. 18
 Bracket 4 – Fixed Charge for Non-CARE/FERA customers with household income of 19 greater than 650% of Federal Poverty Level. 20
a) Lower Average Monthly Bills for Low-Income Customers 21 AB 205 requires that the fixed charge discount be set “so that a low-income ratepayer in 22 each baseline territory would realize a lower average monthly bill without making any changes 23

75 ALJ’s Ruling Providing Additional Guidance for Track A Proposals, Staff Guidance Memo on Using the Public Tool to Prepare Opening Testimony (Mar. 23, 2023), at p. 5. 10/24/2023 D3 101 of 196

44 in usage.”76 As discussed in the Joint IOUs’ Statutory Interpretation Brief, we interpret this to 1 mean that the average low-income customer in all baseline territories must realize at least some 2 bill savings as a result of the IGFC implementation relative to current rate design. In practice, 3 this means that the required discount level is informed by the amount of bill savings realized by 4 low-income customers in the lowest baseline usage territory. Each IOU’s specific Rate Design 5 Testimony exhibit discusses this requirement in more detail. 6 E. Impact of the IGFC on Rates and Other Rate Design Issues 7

1. Impact of the IGFC on Volumetric Rates 8
The Joint IOUs propose to reduce volumetric rates consistent with current rate treatment. 9 For PG&E and SDG&E, as presented in Table II-7, below, this means the revenue from the 10 IGFC would be applied as an equal cents per kWh reduction in the underlying volumetric rate, as 11 none of the costs proposed to be collected through the fixed charge are currently time-12 differentiated on these rates. For SCE, this means applying the volumetric reduction based on 13 the System Average Percent Change (SAPC) methodology consistent with the method used to 14 perform revenue requirement adjustments for all rate classes. However, certain rates require 15 additional consideration, as displayed in Table II-7 and outlined in section II.E.6, below. 16 Table II-7
IOUs’ Volumetric Rate Adjustment Methodology by Rate Schedule

Volumetric Methodology PG&E SDG&E SCE
Standard Rate Schedules: Equal
Cents per kWh or SAPC
E-1

E-TOU-C

E-TOU-D
E-ELEC

DR
TOU-DR1
TOU-DR2
DR-SES
TOU-DR

TOU-ELEC
Domestic
TOU-D (4-9)
TOU-D (5-8)

Other Rate Schedules: IOU
Specific
EV2 EV-TOU
EV-TOU-2
EV-TOU-5

TOU-D-PRIME

76 AB 205 and Cal. Pub. Util. Code § 739.9(e)(1).
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45 Each of the Joint IOUs’ respective inclining block tier non-TOU rates, as well as their 1 respective default TOU rates, currently include two tiers, with all Tier 2 rates (or “above-2 baseline” rates) set 25% higher than Tier 1 (“baseline”) rates, per the CPUC’s residential rate 3 reform tier flattening glidepath decision.77 For PG&E and SCE, this is implemented in the 4 underlying tariffs as the CIA component, while for SDG&E it is implemented as the TRAC 5 component. The Joint IOUs do not propose to change the 1.25:1 tier ratio in existing tiered rates. 6 However, the overall reduction in volumetric rates that results from addition of the IGFC will 7 result in an overall decrease in the $/kWh difference between Tier 1 and Tier 2 rates. 8

2. Adjusting the IGFC Over Time for Revenue Requirement Changes 9 The Joint IOUs propose that, between their respective GRC Phase II proceedings, each of 10 their IGFC rate components, as adopted in the Demand Flexibility OIR, should be updated to 11 follow changes in the underlying revenue requirements. This means that if an IOU’s distribution 12 revenue requirement were to go up or down by 5%, its IGFCs would each change by that same 13 amount. This contrasts with how fixed charges have previously been implemented for the Joint 14 IOUs, where a given fixed charge did not vary when the underlying revenue requirements 15 changed, rather, the difference was made up with other rate components. SCE has already 16 transitioned its TOU-D-PRIME to use the same treatment proposed here. Under the new context 17 here, where the fixed charge rate component must be used as a mechanism to ensure volumetric 18 rates do not inhibit state decarbonization policy, fixed charges must be allowed to change over 19 time. Further, the fixed charge proposals parties are making in this proceeding are distinct from 20 other existing fixed charges for non-residential rates in that they collect more than just a portion 21 of distribution costs; pursuant to AB 205, the Joint IOUs propose that the entirety of several non-22 bypassable charges be collected through the fixed charge, all of which have varying revenue 23 requirements over time. 24

77 D.15-07-001, at p. 330, COL 37.
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46 3. IGFC Review and Assessment Over Time 1
The knowledge of historical performance will not be available to the Joint IOUs when 2 initially setting rates with an IGFC. Over time the IGFC may require adjustments to its structure 3 and method of service as real-world data associated with revenue recovery, customer 4 participation, and equity of rates is obtained. The Joint IOUs propose the following review and 5 assessment process to determine the ongoing success of the IGFC structure. 6 The Joint IOUs propose to conduct the review and assessment process in each of their 7 respective GRC Phase II proceedings. In this manner, the review and assessment will be 8 performed in an already scheduled CPUC proceeding where interested parties are convened to 9 examine the utilities’ marginal cost and rate designs broadly. Including the IGFC structure 10 within these proceedings is an efficient use of resources and will align any changes to the IGFC 11 with changes to the underlying marginal costs and related rate elements, such as time-of-use 12 differential and volumetric rate designs. The GRC Phase II calendar provides an adequate time 13 interval (i.e., four-year cycles) for any changes to take hold before the next assessment, and also 14 allows for mid-cycle Rate Design Window Applications in the event a more immediate 15 adjustment is necessary. 16
The review and assessment of time-of-use pricing periods is conducted in a similar 17 manner. In each GRC Phase II proceeding, the Joint IOUs submit a prescribed78 study to assess 18 if the existing time-of-use pricing periods are still applicable given changes to the underlying 19 costs drivers being evaluated in the GRC Phase II. Parties to the proceeding can then offer 20 supporting or opposing positions through the various vehicles available to them in the regulatory 21 process. An independent evaluation of the arguments presented by parties is then conducted by 22 the CPUC’s Energy Division. 23
The primary metrics to be considered in the assessment relate to revenue recovery and 24 operational requirements. With respect to revenue recovery, the assessment will determine the 25

78 D.17-01-006.
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47 effectiveness of the IGFC structure in recovering the design level of revenue in each of the 1 attrition years. Here parties will examine inputs to rate setting and customer activities to help 2 determine the causes of any deviations, and the methods used to adjust rates in the attrition years. 3 For this purpose, parties will review forecasts of customer distributions across Income Brackets; 4 counts of customers who successfully appeal an Income Bracket placement, and allocation of 5 overall low-income rate benefits. 6

4. CARE Discount Structure Changes 7
AB 205 changed the methodology for determining CARE discounts. Current law 8 requires the “average effective CARE discount…not reflect any charges for which CARE 9 customers are exempted, discounts to fixed charges or other rates paid by non-CARE customers, 10 or bill savings resulting from participation in other programs…79” In addition, current law 11 maintains that the overall average effective CARE discount should be no less than 30% and no 12 greater than 35%. Previously, the CARE discount had been applied on a line-item basis to non-13 exempt billed charges, with an overall bill-to-bill difference relative to a non-CARE bill that 14 reflected an average effective CARE discount of 32.5% for SCE, 35% for PG&E, and 35% for 15 SDG&E. For each of the Joint IOUs, the average effective bill-to-bill CARE discount falls 16 within the statutory guidelines. 17
Consistent with the current language in Public Utilities Code Section 739.1, the Joint 18 IOUs propose a CARE discount structure in which the required 30% to 35% discount limit is 19 applied to non-exempted volumetric charges. Under this construct, the overall CARE customer 20 benefit would include CARE discounted volumetric rates, the low-income fixed charge discount 21 relative to the average fixed charge amount, and exemptions from specific charges to include the 22 CARE surcharge, SGIP, and the DWR Wildfire Fund. Since the IGFC discount required by AB 23 205 exceeds the 35% limit, we propose that only a portion of the IGFC discount be considered 24 part of the CARE program, such that the overall CARE surcharge amount remains unchanged, 25

79 Pub. Util. Code § Section 739.1(c)(1).
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48 with the remainder of the IGFC discount funded within the IGFC. This approach ensures that 1 implementation of the IGFC maintains existing interclass revenue allocations. For an average 2 CARE customer, the sum of benefits would provide an average 45-50% bill-to-bill difference 3 relative to a non-CARE bill, as shown in Tables II-8-10 below. 4 Table II-8
SDG&E Illustrative CARE Bill Comparison
Monthly Bill Charge Average Non-

CARE/ FERA
Average CARE/
FERA
Effective
Discount (%)
Fixed Charge $91 $30 (67)%
Volumetric Charges80 $109 $71 (35)%
Total Bill $200 $100 (50)%

Table II-9
SCE Illustrative CARE Bill Comparison
Monthly Bill Charge Average Non-

CARE/ FERA
Average CARE/
FERA
Effective
Discount (%)
Fixed Charge $60 $18 (70)%
Volumetric Charges81 $106 $74 (30)%
Total Bill $166 $92 (45)%

Table II-10
PG&E Illustrative CARE Bill Comparison
Monthly Bill Charge Average Non-

CARE/ FERA
Average

CARE/ FERA
Effective
Discount (%)
Fixed Charge $65 $23 (65%)
Volumetric Charges82 $104 $65 (37%)
Total Bill $168 $118 (48%)

80 Assumes 400 kWh of usage.
81 Assumes 504 kWh of usage.
82 Assumes 476 kWh of usage.
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49 5. FERA Interaction with IGFC 1
The Family Electric Rate Assistance Program (FERA), as currently implemented, has a 2 statutory 18% line-item discount on non-CARE rates (meaning FERA rates are 82% of non-3 CARE rates).83 To be eligible for FERA, a customer household must be three or more 4 individuals with a combined income from 200% FPL up to 250% FPL. While the statutory 5 language for the CARE program was revised in AB 205 to make it explicitly compatible with the 6 IGFC also required by AB 205, no such changes were made to the statutory language for FERA. 7 Therefore, there is some ambiguity how the FERA program should interact with the IGFC. The 8 Joint IOUs propose that FERA participants be considered part of the second income category 9 along with CARE customers with incomes greater than 100% of FPL. Since the fixed charge in 10 this category is less than 82% of the mid-income bracket fixed charge, let alone 82% of the high-11 income bracket fixed charge, the Joint IOUs propose that this fixed charge discount supersede 12 the 18% discount these customers are entitled to under FERA. FERA participants will continue 13 to receive an 18% discount on non-CARE volumetric rates. The default version of the Public 14 Tool calculates FERA bills using non-CARE fixed charges, rather than the second income 15 bracket fixed charge as proposed by the Joint IOUs. As a result, the bill impacts from the default 16 version of the Public Tool do not reflect the utility proposal. The Joint IOUs also present 17 alternative results using a modified version of the Public Tool that does set all FERA fixed 18 charges at the intended level. Because the Public Tool is not designed to adjust all other rates in 19 response to the reduction in fixed charges paid by FERA customers, this technically understates 20 the rate levels of non-CARE customers. However, the small volume of FERA customers means 21 this has a de minimis impact – for example, only 0.06% less residential revenue is collected for 22 SCE. 23

83 PU Code Section 739.12.
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50 6. Implementation of the IGFC on Non-Default Residential Rates 1 Parties have already submitted legal briefs on statutory interpretation of AB 205. With 2 the exception of the Solar Energy Industries Association (SEIA), all parties’ statutory 3 interpretation briefs appeared to agree that, as both a practical and policy matter, the IGFC must 4 be implemented on all rates. Besides the exceptions outlined below and in individual utility 5 testimony, the IGFC on default rates should be mirrored on all optional rates. To do otherwise 6 would enable higher income customers to easily evade the higher IGFC levels they are intended 7 to pay by switching to a rate without an IGFC (or with a lower IGFC). The impact of the IGFC 8 should be as consistent across rate schedules as possible while allowing some adjustments for 9 pro-electrification policy purposes. 10
There are three general exceptions to this policy: 11
First, the Joint IOUs may each have rates scheduled to be eliminated (for example, 12 PG&E’s EV-A and E-TOU-B rates will be eliminated in 2025). In the interest of simplicity, 13 these rates should retain their existing rate design if they do happen to have any overlap with 14 general IGFC implementation. These specific exceptions are described in more detail in the 15 individual IOU Rate Design chapters. 16
Second, the Joint IOUs’ separately metered EV rates should not have an additional full 17 IGFC, so long as, at the customer’s primary meter (for non-EV household electric usage), takes 18 service on a rate that does have a full IGFC.84 The Joint IOUs’ separately metered EV rates 19 should mirror the overall rate levels of the non-submetering versions of the EV rates, which 20 would include the effects of the fixed charge. However, the separately metered EV rates may 21 still feature fixed charges to recover incremental billing and metering costs, while excluding 22 other costs in the customer charge. 23

84 SCE TOU-D-PRIME separately metered option will continue to reflect a credit for the final line transformer and final line drop costs that are shared with the primary meter. 10/24/2023 D3 108 of 196

51 Third, existing optional residential rates with fixed charges (e.g., PG&E’s E-ELEC 1 (Electric Home) rate, which already has a $15 fixed charge, SDG&E’s Schedules EV-TOU-5 2 and TOU-ELEC, which have $16 fixed charges, or SCE’s TOU-D-PRIME rate) may need to 3 have higher overall fixed charges than the default rate’s IGFCs. If the Joint IOUs’ proposals are 4 accepted, there is no need for these rates to have higher fixed charges than the default IGFC. 5 However, if the CPUC were instead to opt for a set of IGFCs lower than the Joint IOUs’ 6 proposals, these optional rates should always at least collect current levels of distribution fixed 7 charges. For example, if the default rate IGFC collected $10 of NBCs and $7 of distribution 8 costs from non-CARE customers, the E-ELEC fixed charge should be $8 higher to account for 9 the current $15 distribution fixed charge. This will ensure the relative benefit of these optional 10 rates as being more pro-electrification than standard rates is retained until default rate design 11 evolves to more closely match the designs of these optional rates. 12

7. Size Differentiation 13
The Joint IOUs do not propose that the fixed charge be explicitly differentiated by 14 customer size, to avoid undue complexity of the initial IGFC rates. The Joint IOUs understand 15 that Public Utilities Code section 739.9(d)(1) requires that any approved fixed charge 16 “reasonably reflect an appropriate portion of the different costs of serving small and large 17 customers.” This language was added in 2013 through AB 327 and was not modified by AB 18 205. 19
Working with Energy Division, the ALJ’s December 9, 2022 Ruling (requiring legal 20 briefs on legislative intent) hypothesized a potential bundled fixed charge that might be 21 comprised of two elements: first, a set monthly basic service fee that is income graduated, with a 22 possible second “demand charge” element that meets the requirements of the fixed charge 23 definition in 739.9(a) which requires any fixed charge not to vary based on month-to month 24 changes in a customers’ kWh usage, a requirement that might be satisfied if the demand charge 25 were preset using another factor such as maximum amperage. 26 10/24/2023 D3 109 of 196

52 While in theory, the idea of a hybrid IGFC (e.g., with a residential demand charge or 1 other element to reflect size of kW demand), could have merit, there are several difficulties with 2 doing something like that now. The IGFC is already complex given the addition of income 3 graduation, and layering on any size differentiation would make the hybrid fixed charge concept 4 overly complex and more difficult for customers to understand. Thus, the Joint IOUs do not 5 support such a hybrid structure at this time. 6
Our proposed IGFCs nonetheless reflect the same underlying statutory intent. The 7 portion of distribution costs that most clearly vary with the demand of individual customers 8 (MDCC- Primary and Secondary for PG&E, Distribution Design Demand MC for SCE, MDDC 9 for SDG&E) will continue to be collected through volumetric rates, as will all transmission and 10 generations costs. Further, home size is presumably correlated with household income. As such, 11 the income differentiation inherent in the IGFC can (and should) be deemed to be a reasonable 12 proxy for the differing costs of serving large and small customers. This proxy approach avoids 13 adding further complexity, while still accomplishing the overall intent of the statute. 14 However, if the CPUC instead wishes to explore a different approach that adds an 15 express size differentiation component to rates (other than $/kWh charges and the IGFC as a 16 proxy for size), then it should do so in the broader context of demand charge reassessment in 17 Track B of the DFOIR proceeding. That said, regardless of the venue for such a decision, the 18 Joint IOUs do not support the use of either housing type (e.g., single family vs. multifamily) or 19 home electric panel amperage as a basis for such a charge. Either approach presents significant 20 data challenges in that billing quality data is not readily available for either of these two 21 characteristics. Developing billing quality data and reprogramming the billing systems to update 22 such data fields would require additional costs and likely be error-prone. Given that 23 implementation of the basic IGFC will be complex, the CPUC should not compound these 24 difficulties by requiring establishment of other novel billing determinants at this time. 25 As an alternative, the Joint IOUs suggest that the CPUC could explore the concept of a 26 threshold-based demand charge. This concept would involve a demand charge that would only 27 10/24/2023 D3 110 of 196

53 apply to demand beyond a specific level. Such a demand threshold level could be set either 1 based on population statistics of demand levels to ensure relatively few customers are exposed to 2 such a charge, or based on end-use specific load data to ensure the threshold does not expose 3 most customers adopting building/transportation electrification technologies to a demand charge. 4 If the threshold were set at 12 kW (e.g., a 5 kW house load plus a 7 kW level 2 EV charger), a 5 customer with a demand of 15 kW would only be assessed a demand charge on 3 kW. This 6 alternative approach could mitigate some of the traditional concerns with implementing a 7 demand charge on residential rates. 8

8. Elimination of Minimum Bills 9
The Joint IOUs propose to eliminate minimum bills. In R.12-06-013, the CPUC 10 authorized the application of minimum bills to residential customers and approved an amount of 11 $10 for non-CARE customers and $5 for CARE customers.85 Because of the all-volumetric 12 design of residential rates, the minimum bill or minimum charge was instituted as a billing 13 mechanism applied to customers whose monthly usage fell below a minimum amount deemed 14 necessary to support the recovery of costs for power delivery and customer billing. In this 15 proceeding the Joint IOUs’ proposal to set fixed charges at a level to reasonably recover a 16 portion of delivery related costs, customer related costs, and certain public policy costs, at a 17 minimum, negates the need to assess a minimum charge or minimum bill on residential 18 customers. 19
B. Calibration Mechanism for Structure Revisit 20
As discussed in the Cost Recovery Chapter, the Joint IOUs are proposing a calibration 21 mechanism in the event that actual revenue collection from the IGFC varies significantly from 22 forecasted collections. This is discussed in more detail in the Joint IOU Cost Recovery Chapter. 23

85 D.15-07-001, at pp. 283-284, 291.
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54 C. Public Tool Results 1
The Joint IOUs have included the “Printable Results” tab from the Public Tool as 2 Appendix B, as required by the Staff Guidance Memo on March 23, 2023.86 Individual IOU 3 results are discussed in each IOU’s Rate Design Testimony.4

86 Administrative Law Judge’s Ruling Providing Additional Guidance for Track A Proposals, March 23, 2023.
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55 III. 1
INCOME VERIFICATION 2
A. Introduction 3
This Chapter covers the Joint IOUs’ assessment of and proposals for how to accomplish 4 verifying customers’ household incomes, as required to implement the IGFC’s that AB 205 5 directed the CPUC to adopt in this proceeding. 6
Verifying customers’ household incomes will present new challenges for both IOUs and 7 customers. The Joint IOUs explored multiple options with the goal of minimizing anticipated 8 customer pain points, while also maximizing accuracy of the initial income bracket assignment. 9 Many options proved to have challenges of being administratively burdensome, costly, and 10 having unclear levels of accuracy. The Joint IOUs’ proposal aims to reduce these barriers 11 through the use of real, accurate data with a single statewide Third Party implementor. 12 Specifically, the Joint IOUs propose that the income verification process (including the initial 13 Income Bracket placement, customer appeal process, and periodic updates to income bracket 14 assignment) is conducted by a Third Party under the supervision of the CPUC, using a data 15 model that has access to Franchise Tax Board (FTB), Department of Social Services (DSS), and 16 census block data to place customer households in the correct Income Bracket. However, 17 regardless of the adopted approach, all parties should anticipate that due to the newness of the 18 process there will undoubtedly be unforeseen challenges, and possibly high levels of customer 19 resistance despite planned outreach and education, during the initial years of implementation. 20

1. Income Assignment and Verification - Objectives and Evaluation Criteria 21 The primary objective of an income assignment and verification process is to assign 22 customers to the correct Income Bracket based on household income. Secondarily, a further 23 process should be provided to allow any customer to appeal their assignment, as well as a longer-24 term process for periodically monitoring the ongoing accuracy of the household’s assigned 25 10/24/2023 D3 113 of 196

56 Income Bracket. The Joint IOUs recommend that initial income bracket assignments, customer 1 appeals and periodic updates be conducted by a Third Party under contract and supervision of the 2 CPUC. Among other benefits, the Third Party will ensure statewide consistency so that all 3 electric IOUs (small and large) can benefit from economies of scale. Specifically, the Joint IOUs 4 recommend the CPUC overseeing a Third Party, similar to how the CPUC administers income 5 verification for the telecommunication utilities’ LifeLine program utilizing the best available 6 data, including data from the FTB and DSS, to most accurately assign customer to household 7 Income Brackets. 8
Selecting an appropriate process for IGFC income assignment and verification involves 9 competing considerations which must be carefully balanced. These considerations include: (1) 10 customer impact and acceptance, (2) accuracy, (3) cost to implement, (4) complexity, (5) 11 implementation timing, and (6) an accessible and understandable appeals process if a customer 12 seeks a reassessment of their household income bracket assignment. To develop a proposal that 13 meets these objectives and balances these considerations, the Joint IOUs identified multiple 14 evaluation criteria, through input from stakeholder workshops as well as subsequent research and 15 collaborative discussions. The Joint IOUs’ IGFC income verification evaluation criteria are 16 listed below: 17
 Customer Impact and Acceptance 18
o Minimize customers’ privacy concerns about this new collection and use of 19 household income data 20
o Build trust in the income verification process 21
o Enable ease of required customer actions 22
o Facilitate customer understanding and awareness of the new fixed charge rate 23 component, as well as the income verification and appeals process 24 o Enable the income assignment process to be as transparent as possible while 25 protecting privacy 26
o Facilitate a positive and consistent statewide customer experience 27 10/24/2023 D3 114 of 196

57  Accuracy 1
o Make the process as effective and efficient as possible, including for: 2 o Resolving customer appeals claiming an incorrect household income 3 assignment, and 4
o Periodically refreshing household income categorizations for all customers 5 o Minimize free ridership as well as potential impacts to other IOU programs with 6 self-certification enrollment 7
o Minimize inadvertently mis-categorizing low-income customers into other 8 income groups due to verification challenges that low-income customer may face 9 o Select a data source (or sources) that is comprehensive while also simple and 10 cost-effective 11
 Cost 12
o Minimize initial start-up costs to implement 13
o Minimize ongoing operating, labor, communications, data storage and 14 maintenance costs 15
 Complexity 16
o Avoid requiring unduly complex systems 17
o Minimize manual processes 18
o Limit the resource burden and cost of ongoing maintenance 19 o Minimize the number of customer appeals 20
o Make the appeals process simple to implement and easy to access 21  Time to Implement 22
o Balance expediency of implementation with accuracy of income bracket 23 assignment and degree of effectiveness 24
o Consider timing effects of either complying with existing statutes or seeking 25 possible legislative amendments that may be needed for the most optimal 26 approach 27
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58 o Availability of information for and speed of placement of new California 1 residents in the correct Income Bracket 2
D. Stakeholder Input 3

1. Key Stakeholder Input 4
The Joint IOUs sought feedback from a diverse group of stakeholders regarding income 5 verification process options. To this end, PG&E requested an IOU-facilitated follow-up 6 workshop noticed to all parties, which was held on December 21, 2022. One key insight gained 7 from this workshop was that a consistent approach is needed across the small and large IOUs that 8 could leverage existing data to the maximum extent possible. Some stakeholders also noted that 9 the IOUs may not be the best choice to conduct income verification. As presented in Chapter 5 10 of this exhibit, marketing research has already revealed that customers do not want their IOU to 11 collect their income. 12
E. Income Definition 13
The Joint IOUs recommend that the definition of qualifying income that has already been 14 established for the CARE program (e.g., Wages, Social Security, Pensions, Child Support) 15 should be used as the starting point for identifying the fixed charge Income Bracket into which 16 low-income customers should be placed. By doing so, a consistent definition of “income” would 17 be used across the CARE program as well as the new IGFC rate component’s household Income 18 Brackets. The CARE program is an opt-in program with an application through which 19 customers self-certify that their income is within the qualifying threshold (or by self-certifying 20 that they qualify through categorical eligibility by participating in one of several listed 21 programs). Because the definition of qualifying income was first established through the Low 22 Income proceeding, the Joint IOUs recommend that further discussion or review of the definition 23 of qualifying income be conducted in that proceeding. The Joint IOUs recommend that the time 24 component of qualifying income be aligned with calendar year. 25 10/24/2023 D3 116 of 196

59 F. Household Income Brackets 1
As discussed in the Rate Design chapter of this exhibit, the Joint IOUs recommend four 2 fixed charge household Income Brackets. The Joint IOUs developed their recommended Income 3 Bracket proposal by, first, creating two low-income brackets, namely: (1) Income Bracket 1 4 (extra discounted) for CARE customers with household incomes of 100% FPL and below, and 5 (2) Income Bracket 2 (discounted) for CARE customers with household incomes greater than 6 100%, plus FERA enrolled customers. Sub-dividing the group of low-income customers into 7 two brackets allows the most economically vulnerable households to receive a lower fixed 8 charge than that which would result from blending these two subcategories into a single 9 category. 10
Next, the Joint IOUs divided the Non-CARE/FERA households into the third and fourth 11 household Income Brackets: (3) Non-CARE/FERA customers with household income up to or 12 equal to 650% of Federal Poverty Level, and (4) all remaining Non-CARE/FERA households, 13 with incomes starting at 650% FPL. Providing two Income Brackets above the two lowest 14 brackets provides some relief for moderate-income households while carrying out AB 205’s 15 intent that low-income customers pay “a smaller fixed charge and high-income customers pay a 16 higher fixed charge.”87 By providing two levels of progressively higher non-low-income fixed 17 charges, the Joint IOUs are balancing the desire for simplicity with equity concerns. This 18 proposed design results in an equitable distribution of IGFC impact among very low, low, 19 moderate- and higher-income households. 20
The proposed household Income Brackets and estimated number of customers in each 21 bracket are shown in the Table III-11. 22

87 Pub. Util. Code § 739.9(e)(2).
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60 Table III-11
Joint IOUs Percentage of Residential Customers by Income Brackets

Income
Bracket
Income Bracket Eligibility Estimated Percentage of Total Residential Customers88

PG&E SDG&E SCE
1 CARE Customers
0% to 100% FPL 13% 12% 11%
2 CARE/FERA Customers
> 100% FPL 15% 15% 15%
3 Non-CARE/FERA Customers
650% FPL 25% 23% 19%
G. Income Verification Options Evaluated by the Joint IOUs 1

1. Introduction 2
The Joint IOUs investigated methods for determining and verifying customer household 3 income for the purpose of assigning a monthly fixed charge, including: 4 (1) using currently available income data from the income qualified programs 5 administered by the Joint IOUs, 6
(2) leveraging available state processes such as the CalFresh Confirm process or the 7 CPUC-administered LifeLine (TelCom low-income) Program89, 8 (3) partnering with consumer credit reporting companies to access and match household 9 income data, 10
(4) using customer stated or verified income data, and 11 (5) using an IOU-developed data model to verify income data. 12 All of these methods have significant hurdles that would need to be overcome to 13 effectively verify income for the purpose of assigning a monthly fixed charge. This discussion is 14

88 Using the data in the Public Tool.
89 As suggested in the Energy Division’s Income Graduated Fixed Charge Guidance Memo issued January 17, 2023.
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61 intended to serve as a list of the most thoroughly investigated proposals but does not represent an 1 exhaustive list of all ideas considered. 2

2. Using Current Program Information 3
Currently, the Joint IOUs receive customer-supplied income data to verify eligibility for 4 income qualified opt-in programs including CARE/FERA, and Energy Savings Assistance 5 (ESA). 6
For the ESA program, participation is temporary because energy efficiency services 7 occur at a single point in time. Accordingly, ESA applicants provide qualifying income 8 information when they apply to participate. While this income data is eventually verified during 9 the enrollment process, such a process would not be useful for assessing an ongoing fixed charge 10 because: (1) the income information is only provided as part of initial enrollment and (2) 11 applications for these programs are handled by contractor networks that could not scale to handle 12 the full residential customer population. 13
In contrast, CARE and FERA are ongoing opt-in income-qualified programs, which 14 allow customers to continue to participate year-over-year as long as they remain eligible. 15 Initially, CARE/FERA eligibility is determined during enrollment through self-reported data that 16 customers include in their application. The initial CARE/FERA self-certified information 17 includes: (1) household size and (2) either proof of (a) their participation in one or more public 18 assistance programs or (b) their household income90 and income sources. Every year, each large 19 IOU validates a sample of its CARE/FERA-enrolled customers through a Post-Enrollment 20 Verification process through which SCE, PG&E, and SDG&E validate approximately 7%, 8%, 21 and 6% of enrolled customers, respectively. The Joint IOUs do not collect income data from 22

90 The SCE and SDG&E CARE/FERA applications have a “fill in the blank” question for customer income level. The PG&E CARE/FERA application includes a selection of income ranges and asks the customer to “check a box”. As a result, SCE and SDG&E have information on a customer’s specific income level while PG&E currently has a customer’s income range. PG&E will begin collecting specific income information in mid-2023 for new CARE applicants and customers undergoing recertification.
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62 customers for purposes other than enrollment in income qualified programs. Also, because that 1 information only covers a subset of the residential population and is (a) only verified once during 2 enrollment (in the case of ESA and similar programs) for all applicants, and (b) re-verified on an 3 irregular basis for some (not all) CARE/FERA-enrolled customers, this process is not robust 4 enough to be appropriately relied upon for determining the level of a mandatory monthly income 5 graduated fixed charge on a long-term basis. Further discussion about the challenges of building 6 on the CARE/FERA processes to expand to income verification or stated income collection to 7 customers of all income levels can be found further below, in the “Using Customer Stated or 8 Verified Income” section (III.E.5). 9

3. Using Available State Processes 10
a) DSS’s “CalFresh Confirm” Data 11
The Joint IOUs also investigated whether the DSS’s CalFresh Confirm process might be 12 a useful means of income verification for the IGFC. The Joint IOUs reviewed documentation on 13 CalFresh program eligibility and income verification methods and also spoke with program 14 administrators from the DSS as well as one of the data providers for the CalFresh verification 15 program. 16
The CalFresh Confirm process could enable verification that a customer is a CalFresh 17 recipient, and therefore has a household income <200% of the FPL. However, the Joint IOUs 18 determined that the CalFresh Confirm system has several significant limitations, most notably 19 that it does not match the Joint IOUs’ proposed household Income Brackets. It only confirms 20 whether the information entered matches the information for an individual CalFresh recipient, 21 which would only be partially useful in trying to validate whether the total household income 22 makes that residential account eligible for either Income Bracket 1 or 2. However, income 23 verification for customers with low incomes who are not CalFresh recipients, as well as 24 moderate- and higher-income customers, cannot currently be accomplished by CalFresh. In 25 general, the CalFresh program in its current form would not be immediately transferrable to 26 10/24/2023 D3 120 of 196

63 income verification for the purposes of the IGFC, since it uses only a single income cut-off that 1 does not match the proposed total household cut-offs for establishing two low income-graduated 2 fixed charge brackets. It is conceivable that a Third-Party verification process could be built 3 using the same underlying data but including additional income cut-offs. However, the Joint 4 IOUs understand that at least one of the data-sources underlying CalFresh is credit agency data 5 that requires affirmative customer consent to complete the verification, which poses significant 6 administrative challenges for the IGFC. In this situation, affirmative customer consent would 7 have to be collected from each and every one of the Joint IOUs’ 10.8 million residential 8 customer accounts. This would not just have to be done once during the initial deployment, but 9 repeatedly, as individual as well as household income varies over a person’s lifetime.91 In 10 addition, consent would have to be obtained for each new account turn-on, from both the named 11 customers on the account as well as every other individual in their household. The repeated, 12 large-scale collection of such consent documentation would be costly and would impose a 13 significant burden on customers (as well as dilute the IGFC’s benefits for electrification if 14 verification costs were included in rates). Further, it is likely many customers would not 15 respond.92 Under this kind of verification model, non-respondents may have to be placed on a 16 higher ‘default’ Income Bracket, which could cause equity concerns for customers who are 17 legitimately eligible for a lower fixed charge but failed to respond. 18

91 Year over year income variation reached 25 percent or more for a quarter of households between 2004 and 2005. Congressional Budget Office, Recent Trends in the Variability of Individual Earnings and Household Income (June 2008), available at https://www.cbo.gov/publication/41714?index=9507 .
92 Section E.5 of this exhibit discusses available information on customer response rate to the CARE Post Enrollment Verification process, which can be used as a proxy to indicate customer likelihood to respond to consent requests.
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64 b) CPUC/ Third Party LifeLine Low Income Program for Telecom 1 Utilities 2
The Joint IOUs also reviewed the Telecommunications’ LifeLine program’s income 3 verification process, to see if a similar process could be used to verify income for the IGFC. The 4 LifeLine income verification program is administered through a CPUC interagency contract with 5 a Third Party, an organization called Maximus. The LifeLine process requires customers to go 6 through an income verification process at the time of enrollment as well as automated 7 recertification. The LifeLine program primarily uses enrollment in CalFresh (51%) or MediCal 8 (43%) as a proxy to confirm LifeLine eligibility, but also accepts enrollment in other programs, 9 or proof of Federal/State income or Supplemental Security Income (SSI).93 The LifeLine 10 program, which serves approximately 1.3 million households,94 currently costs $46 million for 11 the three years between October 2022 - October 2025 to administer (including enrollment of 12 applicants, verification of Income Brackets, operation of information technology systems, 13 operation of a call center, and database management).95 The Joint IOUs have not been able to 14 determine what portion of program funding is used to verify customer income but note that even 15 its current steady state cost of approximately $11.80 per customer per year is significant, 16 especially given that 94% of eligibility is being verified through enrollment in other state 17 programs. In addition, CPUC decisions show that the LifeLine program initially had significant 18 challenges that required adjustments resulting in today’s program.96 Thus, LifeLine’s current 19

93 Consensus and Collaboration Program and Institute for Social Research, California State University, Sacramento, California LifeLine Program Assessment & Evaluation(May 2022), at p. 38 available at https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M478/K367/478367564.PDF . 94 Id., at p.18.
95 See Administrative Law Judge’s Ruling Providing Guidance for Phase 1 Track A Proposals and Requesting Comments on a Consulting Services Proposal (Jan. 17, 2023), Attachment 1, R.22-07- 005, Phase 1 Track A: Income Graduated Fixed Charge Guidance Memo, at p. 10. This $46 million over three years comes out to an average of 15.3 million per year for 1.3 million households, or about $11.80 per household per year.
96 The Joint IOUs would appreciate assistance from Energy Division in researching what the earlier costs were for the LifeLine programs’ income verification administration by the CPUC, which would be more comparable to the start-up nature of the IGFC.
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65 costs are not directly transferable for IGFC income verification because the majority of IOU 1 customers have household incomes above LifeLine requirements or do not otherwise qualify for 2 income-qualified public assistance programs that could be used as a proxy. Customer 3 households with incomes above the LifeLine income requirements will instead require income 4 verification through more complex means, such as review of tax records or income statements, 5 which is likely to be more costly than using a proxy as is done for 94% of LifeLine customers. 6 Furthermore, whereas 98% of LifeLine applicants verify income in person through the direct 7 application process,97 it is unlikely that a similar process would scale to meet the income 8 application needs of the Joint IOUs’ approximately 10.8 million residential electric customers. 9 For these reasons, the Joint IOUs conclude that though the LifeLine program provides an 10 example of a centralized CPUC managed Third Party income verification process, its processes 11 and current costs are not likely to be a direct indicator of the structure or costs of the type of 12 Third Party administered income verification needed to support an IGFC. Like CARE/FERA, 13 the LifeLine program is a discount program for low income households, and its income 14 verification requirements put the onus on a customer to seek enrollment and prove income 15 eligibility by way of documentation or enrollment in another income-qualified program. 16 Nevertheless, the LifeLine income verification process provides a workable example for having 17 a Third Party administrator handle income verification under the Commission’s direction. 18

4. Using Credit Agency Data 19
The Joint IOUs investigated whether a Third Party could partner with consumer credit 20 reporting agencies to access and match household income data for IGFC household bracket 21 assignments, appeals, and periodic refreshes. The Joint IOUs found that existing products 22 provided by credit agencies, such as Experian’s “Income Insight,” and Equifax’s “Work 23 Number” are not designed to be the sole source of data for decision making to determine income 24

97 Consensus and Collaboration Program and Institute for Social Research, California State University, Sacramento, California LifeLine Program Assessment & Evaluation (May 2022), at p. 38, available at https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M478/K367/478367564.PDF . 10/24/2023 D3 123 of 196

66 categorization98, as discussed below. Rather, they were developed to 1) provide information 1 useful for marketing products to a specific income segment, or 2) serve as a check against 2 income information that has already been received from a potential customer. The Joint IOUs 3 understand that Equifax’s “Work Number” product is used to verify eligibility for several state-4 level social programs such as Medicaid, Supplemental Nutrition Assistance Program (SNAP), 5 Public Housing, and for child support enforcement, but it requires affirmative customer consent. 6 In addition, the Joint IOUs found that these types of products primarily source their income 7 information from payroll reporting data but contain only limited or no data on other sources of 8 income (such as pensions, investments, rental income, child support, etc.), and similarly require 9 customer consent to access. 10
When considering the Joint IOUs’ use case of assigning an IGFC using income data 11 models, the contacted credit agencies relayed that this was not the intended use of their product, 12 would violate the terms of use, and may be inconsistent with the Fair Credit Reporting Act 13 and/or other credit laws. When presented with an alternative use case of placing all customers 14 into the highest Income Bracket and allowing customers to apply for a lower bracket, credit 15 agencies responded that their products could be used to corroborate a customer’s stated income 16 as long as in the case of a mismatch between the customer’s income statement and the credit 17 agency data, the customer retained the option to verify their income with documentation. While 18 this use case is allowable, the Joint IOUs do not find it feasible because 1) it would require 19 defaulting customers to the highest household Income Bracket which would result in customers 20 being assigned a fixed charge that is potentially higher than appropriate for their actual income; 21 2) these products mostly rely on payroll data which will leave significant gaps for customers 22 whose income is not based on reported payroll wages; 3) it would be burdensome to require the 23 majority of customers to contact the Joint IOUs and provide consent for Joint IOUs to use credit 24

98 Credit agencies the Joint IOUs spoke with relayed that their products could not be used in ways that would result in adverse action against a customer, and placing customers in different price levels could be construed as adverse action.
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67 data to confirm their income and assign them to the correct Income Bracket; 4) it would result in 1 operational impacts such as high call volumes, and frequent Income Bracket changes; and 5) it 2 does not provide a pathway for the Joint IOUs to update income data for a customer except with 3 customer consent, which means the Joint IOUs would have to rely on stale data or receive a new 4 customer permission each time to check their stated income against a credit agency product. 5 Across the US, several government programs rely on the “Work Number” product by 6 Equifax for verification of income eligibility, for social programs such as Medicaid, SNAP, 7 Public Housing, or for child support enforcement. This product contains income data provided 8 by employers and payroll providers. This product has the advantage of covering nationwide 9 payroll data and eliminates the need for manual verification of payroll income. However, while 10 the “Work Number” product provides a high level of confidence for a portion of payroll data it 11 does not provide data on other sources of income; thus, it would not provide an accurate 12 estimation of actual household income information. A process would still have to be devised to 13 handle customers without a match in these income databases (including but not limited to new 14 U.S. residents with no prior income record, young customers with no prior income record, and 15 non-person account owners (such as businesses which hold accounts on residential rates). 16 Simply defaulting such customers to the highest bracket of the IGFC would be financially 17 impactful to many legitimately lower income customers. For example, a student moving away 18 for college and with no prior income record would be assessed the highest fixed charge, even if 19 they legitimately have no income. In addition to customers without a match, payroll data may 20 also underestimate total income for certain customers. A shortcoming of payroll data is that it 21 does not capture data from income sources other than payroll records, which would significantly 22 underestimate real household income for certain segments of the population, e.g., those with 23 investment income, such as seniors who may be living on a fixed income such as a pension plus 24 social security, but whose total net worth is quite high. Based on IRS data for federal tax returns, 25 about 20% of individuals residing in California who filed a federal tax return had no income 26 10/24/2023 D3 125 of 196

68 from salary or wages99 which suggests that the individuals in this 20% of California’s population 1 may not show up in payroll data. More importantly though, Equifax’s “Work Number” product 2 does not allow for pre-assignment of income data to each household, rather it only permits 3 Equifax to share income data about the customer verification after receiving permission from 4 that customer for Equifax to share data about the customer. There is also no refresh ability 5 without additional permission from the customer, which is problematic given data for some 6 customers is known to be highly variable over time. 7
Based on the research the Joint IOUs have been able to complete thus far, the Joint IOUs 8 have determined that data sets available for purchase from credit reporting agencies are not 9 designed to be used as the source of data for assigning an income categorized fixed charge 10 bracket and attempting to use these data sets for this purpose may not be authorized by the data 11 protection laws with which credit agencies are required to comply. Overcoming existing credit 12 data protection laws, including the FCRA, appears to require either: (1) obtaining consent from 13 each of over 10 million customers to use their income data (which was not viewed as being 14 practicable on such a wide scale, for a rate component that is required rather than an “opt-in”), or 15 (2) obtaining an amendment to the FCRA statute that exempts provision of data for IGFC 16 purposes (which seems unlikely to happen in time, or at all, given the many interest groups who 17 might object or seek their own exemptions). 18

5. Using Customer Stated or Verified Income Data 19
Due to the constraints on the availability of income data described above, the Joint IOUs 20 explored the option of obtaining and verifying data from all customers directly. Even more than 21 obtaining consent from all customers to use credit agency data, obtaining stated income data 22 directly from all customers is not practicable due to high cost and customer impact. The 23

99 In 2020, according to the Internal Revenue Service, only 80% of federal income tax filers residing in California had income from salaries or wages, IRS: SOI Tax Stats - Adjusted Gross Income (AGI) Percentile Data by State, available at https://www.irs.gov/statistics/soi-tax-stats-historic-table-2 . 100 The customer population enrolled in CARE/FERA is 24%, 25% and 27% for PG&E, SCE, and SDG&E respectively.
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69 CARE/FERA program experience is useful to consider as it does collect some stated income 1 data. Approximately one quarter100 of the Joint IOUs’ total residential customer base are 2 currently enrolled in CARE/FERA programs. Of these, approximately 40% of current 3 CARE/FERA enrollees were enrolled in the program based on the customer’s own statement of 4 household size and total household income, whereas approximately 50% were enrolled based on 5 their stated participation in one or more ”proxy” assistance programs (see above) the final 10% 6 were enrolled due to known participation in another income qualified program.101 Most 7 customers on CARE/FERA must recertify their eligibility every two years (four years for 8 customers on a fixed income). 9
Each year, the Joint IOUs require approximately 6%-8% of their CARE/FERA 10 participants to verify their stated information or else they will be removed from the program. Of 11 the verification group, only about 28% respond and complete the verification process; the 12 remaining 72%102 who do not reply are removed from the opt-in CARE/FERA programs until 13 they can apply again and certify their household is income-qualified. The Joint IOU’s 2022 costs 14 for CARE and FERA income verification were approximately $2.1 million, which represents 15 about $9 per customer verified.103 This process, however, is not appropriate for the IGFC, 16 because customers who fail to respond cannot simply be removed from the IGFC. Fixed charges 17 are mandatory, and presumably, non-respondents and customers who fail to recertify every 2 or 4 18 years would be defaulted to a predetermined fixed charge such as the highest fixed charge until 19 proven otherwise. 20

100 The customer population enrolled in CARE/FERA is 24%, 25% and 27% for PG&E, SCE, and SDG&E respectively.
101 Monthly Reports of PG&E, SCE, and SDG&E on Low Income Assistance Programs for December 2022 available at https://liob.cpuc.ca.gov/monthly-annual-reports/ . 102 Opinion Dynamics, 2019 California Low Income Needs Assessment , Final Report (Dec. 13, 2019), (hereinafter 2019 LINA Report), available at https://www.cpuc.ca.gov/-/media/cpuc- website/divisions/energy-division/documents/energy-efficiency/iqap/2019linavol3.pdf. 103 Monthly Reports of PG&E, SCE, and SDG&E on Low Income Assistance Programs for December 2022 available at https://liob.cpuc.ca.gov/monthly-annual-reports/ as mentioned in section E2 above , this represents steady state program verification cost not the CARE start-up verification cost which are believed to have been higher, but research continues. 10/24/2023 D3 127 of 196

70 The 2019 Low Income Needs Assessment (LINA) Report sheds further light on the 1 process challenges of the CARE program’s recertification and verification methods.104 For the 2 2018 program year, about 28% of CARE participants statewide were selected for post-3 enrollment processes, of which: 4
• 21% were due for recertification (i.e., renewal application), with 39% of those being 5 removed from the program, and 61% retained. 6
• 4% were selected for income verification, with 69% of those removed from CARE 7 and 31% retained. 8
• 3% were selected for income verification due to high usage, 96% were removed from 9 CARE and 4% were retained. 10
According to the LINA Report, the post-enrollment processes perform well at removing 11 income-ineligible customers from CARE, however, LINA survey evidence also shows many 12 removed participants reporting that the removals had not necessarily been income-related. 13 Specifically, the 2019 LINA Report’s survey of customers no longer on CARE showed: 42% 14 reported the reason for removal as “inconvenience/forgot,” 23% “didn’t know how to continue,”, 15 and 9% reported “issues with the process.” This suggests that there are process issues that 16 prevent many eligible customers from responding to CARE recertification or verification 17 outreach. 18
These findings from the 2019 LINA Report suggest that modeling income information 19 collection and verification on CARE processes could result in many customers being defaulted to 20 higher income categories than may be warranted, simply due to not providing or certifying 21 income information. In the CARE program, such customers tend to then call the IOU once they 22 receive a higher, non-CARE bill and seek to get back on the program, which creates both a 23 burden on the customer as well as program operational impacts (call center resources, billing 24 processing etc.). This also suggests that basing income bracket assignments on a high-quality 25

104 2019 LINA Report.
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71 data source would significantly lessen customer and operational burdens on individuals and 1 systems as opposed to a method modeled on CARE-type processes. 2 Examining the CARE program’s income verification process and costs illustrates that an 3 IOU-led process similar to the CARE Post-Enrollment Verification process would be 4 unreasonable and exceedingly expensive to scale to the entire electric residential population. For 5 the Joint IOUs, the cost of CARE Post-Enrollment Verification in 2022 was $2.1 million, to 6 verify the selected subset of approximately 230,000 CARE customers. This equates to 7 approximately $9 per customer on average105. But such average cost per customer is based on 8 current CARE processes after decades of refinement, such that the per-customer costs for 9 administering a completely novel IGFC income verification process would almost certainly be 10 higher due to startup costs. Scaling the current CARE verification cost of approximately $9 per 11 customer to the entire 10.8 million electric joint-IOU customers who need to have income 12 assessed to determine the IGFC bracket for each and every customer (since IGFC is not an opt-in 13 program) would put the cost at approximately $97 million. However, initial annual costs would 14 likely reach upwards of $100 million to implement when also factoring in startup costs (which 15 the cited $9 per customer cost does not include).106 16 If verifying all customer income information is cost-prohibitive, proceeding only with 17 customer self-stated income information is unreasonable for reasons of accuracy and billing 18 integrity. There would be little incentive for a high-income customer to provide accurate data 19 and it is also likely that a significant portion of customers would fail to provide income data,107 20 forcing those customers to be assessed the default fixed charge. 21

105 Monthly Reports of PG&E, SCE, and SDG&E on Low Income Assistance Programs for December 2022 are available at https://liob.cpuc.ca.gov/monthly-annual-reports/ . 106 The Joint IOUs are still researching the earlier level of CARE income verification costs closer to the time CARE was started, if available. Start-up costs for the IGFC are likely to differ from and be more expensive than CARE both because the IGFC is not an opt-in program requiring initial self- certification but also involves all levels of income so it would have to process about ten times as many customers’ household income verifications per year. 107 PG&E’s and SCE’s research demonstrate that customers are uncomfortable with IOUs having their income data.
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72 With this in mind, the Joint IOUs considered and rejected a stated income approach, due 1 to severe downstream financial and operational impacts and significant adverse customer 2 impacts. This approach would collect stated income from all customers and then verify income 3 for a subset of customers (e.g., a similar percentage as the CARE/FERA programs, that is, 7-9% 4 annually). However, many customers would likely not submit their income information and it is 5 unclear how many customer appeals this will result in, and what the corresponding total cost to 6 process these appeals would be. If the analysis used the current steady-state CARE/FERA 7 application processing cost of approximately $2-3 per customer (which is likely lower than any 8 new and larger-scale program like the IGFC), the upfront stated income collection could cost 9 approximately $25-30M each time the data were refreshed, but this would likely be dwarfed by 10 the cost of a high volume of appeals. It would also require every customer to repeatedly take 11 action to report income, imposing a significant burden on customers. Stated income collection, 12 at a minimum, would require notification of each customer and processing information received 13 from the customers. Such an approach would likely be more operationally impactful and cost-14 prohibitive than other potential approaches (but more research is needed to make valid estimates 15 to compare). Notably, income information would need to be requested from every customer both 16 before launch as well as periodically thereafter (e.g., every 1-2 years), and a secure system would 17 have to be designed and implemented to collect, store, and update customer stated income 18 information through various channels, such as business reply cards, the call center, and online 19 self-service, so as to protect customer privacy concerns. Too much is unknown about the stated 20 income collection approach, but what is understood caused the Joint IOUs not to propose it. 21 Most importantly, collecting stated income directly could result in a large number of non-22 responses. As noted above, the 2019 LINA study108 provided evidence that there is a large drop-23 off of customers from CARE during recertification (61% retained) and even more so during 24 income verification (only 31% retained) due to reasons other than income qualification. For 25

108 2019 LINA Report.
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73 instance, it is possible that customers do not read/open their mail, or do not know how to 1 complete the income verification. Per LINA, two thirds of removed customers experienced 2 process issues with CARE that prevented them from remaining on the program. If two thirds of 3 the 39% of customers removed during recertification were removed due to non-response or other 4 process issues, this suggests that a quarter of all prior participants fail to reenroll in CARE due to 5 process issues. Conceivably, collecting stated or verified income data from customers for the 6 purposes of the income-graduated fixed charge would encounter similar process barriers as the 7 CARE program. If the non-response rate approaches 25%, it could trigger a large number of 8 appeals down the road. 9
Therefore, the Joint IOUs have concluded that an IOU-administered income verification 10 process that seeks to collect customer-stated income information directly from each customer 11 would not only be cost-prohibitive but would likely result in larger numbers of customer non-12 responses and refusals to provide household income data, due to both process barriers and 13 privacy concerns regarding the Joint IOUs’ possession of their household’s specific total income 14 data. Simply assigning non-respondent customers to the fixed charge for the highest income 15 category would result in financial impacts to customers who should have been made eligible for 16 a lower fixed charge, but who failed to submit income information. The Joint IOUs considered 17 whether such customers could instead be assigned to the fixed charge for the moderate-income 18 level, but this would create disincentives for high-income customers to provide income data 19 which in turn could result in under collections or would dampen the IGFC’s ability to reduce 20 fixed charges for low-income customers, as fewer customers would be paying the higher income 21 fixed charge. 22

6. IOU Developed Data Model 23
Another option the Joint IOUs considered was to predict income based on publicly 24 available data points. Developing an income data model is also challenging due to a lack of 25 publicly available source data that can be used as a reliable proxy for income at the household 26 10/24/2023 D3 131 of 196

74 level. While there is publicly available data on aggregate incomes by area, such as by census 1 tract from e.g., the Current Population Survey109, American Community Survey110, etc. that can 2 be useful to discern income trends among populations and communities, such data is not reliable 3 for predicting each individual household’s income within that area. Using census tract income 4 data to assess an IGFC could result in significant under-identification of low-income customers 5 living in moderate- and higher-income census tracts, and vice versa. For these reasons, the Joint 6 IOUs do not recommend using current publicly available data or developing internal models to 7 determine and verify customer household income solely based on population data. It is 8 important for IGFC income bracket placement to be as fair and accurate as practicable, to 9 minimize customer appeals and to stabilize IOU revenue collection and resulting rates. Using 10 modeled data would not be likely to provide accurate results, which could undermine trust and 11 result in operationally unsustainable levels of appeals. 12

7. Key Findings on Evaluated Options 13
The options evaluated above did not lead to emergence of any single clear-cut solution 14 that would minimize customer action, while also providing highly accurate results in a manner 15 that is feasible, ensures billing integrity and is cost effective. To summarize: 1) Neither current 16 program information nor current state programs are directly adaptable to the needs of income 17 verification for fixed charge purposes; 2) Population-based data models cannot accurately predict 18 individual household income; 3) The direct collection of customer-stated income is costly and 19 burdensome and will likely result in considerable non-response; and 4) Obtaining affirmative 20 consent to use credit-agency data, while somewhat more accurate and less burdensome to the 21 customer, is still costly and the lack of data will likely affect a significant portion of customers. 22

109 Current Population Survey Data available at https://www.census.gov/programs- surveys/cps/data.html.
110 American Community Survey Data available at https://www.census.gov/programs- surveys/acs/data.html.
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75 There are two reasons the Joint IOUs have concluded that accurate initial income bracket 1 assignments are essential to have before the initial launch of any IGFC. First, by presenting 2 customers with an accurate initial income level assignment, customer trust and acceptance of the 3 new IGFC is anticipated to be higher. If, instead, there is a higher degree of inaccuracy in the 4 initial income bracket assignments, customers are likely to question the overall implementation 5 of the rate structure, they may be less likely to accept the change, and the Joint IOUs will have to 6 address high levels of customer dissatisfaction. Second, inaccurate initial assignments would 7 result in more customers filing appeals seeking to be placed in an alternate income bracket. This 8 would drive up costs to manage the higher volume of appeals. Focusing solely on the cost of 9 appeals while using the CARE Post-Enrollment Verification system as a proxy for costs, an 10 initial income bracket assignment process that results in 20% of customers appealing could result 11 in approximately $20 million in costs across the Joint IOUs service territories. Given the data 12 above about lack of Federal income information or State tax filings for over 20% of Californians, 13 it seems more likely that the appeal rate might be higher than 20%. Many of the millions of non-14 low-income customers could also disagree with the results (given that it’s based on household 15 income, not one individual’s return). 16
It Is impossible to know the exact degree of accuracy of any of the methods described 17 above without conducting an actual data analysis using real customer income data, but pursuing 18 a method that has even a 20% appeal rate would be costly. Aside from such Credit Agency 19 products likely not being available for direct income verification without affirmative customer 20 consent due to legal constraints, the Joint IOUs review of available credit agency data suggests 21 error rates in excess of 10-20% assumed in the cost estimates above. This would impose very 22 significant administrative costs no matter who is running the program, and would certainly result 23 in a more negative customer experience than under a more accurate process. 24 A high number of customer income bracket appeals could also impact utility revenue 25 stability as the utility would need to adjust rates the following year to account for the misplaced 26 customers. One of the benefits of the IGFC rate structure is that it is anticipated to stabilize rates 27 10/24/2023 D3 133 of 196

76 for residential customers. Adopting an income bracket assignment process and data source that 1 is less accurate puts this benefit at risk. 2

8. Recommendation 3
Based on the initial research above and the necessity of accurate income bracket 4 assignments, the Joint IOUs have concluded that the optimal approach would be for the CPUC to 5 contract with a Third Party that would use actual income data on a consistent statewide basis. 6 The LifeLine program provides a precedent for having a Third-Party administrator handle 7 income verification under the Commission’s direction. In D.05-04-026, the Commission 8 concluded that income certification/verification should be performed by a Third Party 9 Administrator (TPA) “under the direction of a state agency, namely the Commission.”111 As 10 noted above, the LifeLine program is targeted towards low-income customers and therefore not 11 directly transferable to the requirements for a fixed charge at various Income Brackets, but it 12 nevertheless provides proof that Third Party administration is an established and workable model 13 for income verification purposes. 14
Under such a model, each customer would be assigned to an Income Bracket based on 15 available data specific to their household, and then be given an opportunity to appeal -- as 16 opposed to having to proactively submit income data. The primary venue for obtaining such 17 income verification data would be California’s FTB. In 2020, the FTB received approximately 18

18.5 million state income tax returns112, covering 13.2 million California households113 and over 19 39 million inhabitants. However, it is estimated that the FTB does not have income information 20 for up to 20% of California households who do not file any state income tax return114. A 21

111 D.05-04-026, at p. 26.
112 Franchise Tax Board, Personal Income Tax (PIT) Annual Report 2021, available at https://data.ftb.ca.gov/California-Personal-Income-Tax/PIT-Annual-Report-2021/y7ws-kpcd . 113 There are more individual tax returns than households because more than one earner can live at the same address.
114 The Joint IOUs estimate that up to 20% of customers may be missing from an FTB data set through an analysis reviewing Census demographic data and FTB County resident tax filing data. 10/24/2023 D3 134 of 196

77 customer may choose not to submit a California income tax return if they file as a single 1 individual and earn less than $20,913 per year 115. This suggests that the pool of customers who 2 do not file state tax returns are likely to predominantly be part of lower-income households. To 3 address this gap, additional data from the California DSS’ CalFresh program should also be 4 included as part of the verification process, to provide additional income data for lower-income 5 customers who may not be included in the FTB data set. As an example of how this could work, 6 LifeLine executed an interagency agreement to use the CalFresh verification results.116 It is 7 conceivable that CalFresh verification could be enhanced to use the underlying data sources to 8 meet the needs of income verification for the purposes of the electric fixed charge. One 9 challenge remains obtaining customer consent for this step, but that would be for a much smaller 10 group of customers without any FTB data match. 11
An amendment to the existing California Revenue & Taxation Code would appear 12 necessary to allow the FTB to accomplish mass provision of individuals’ income data to any 13 outside entity administering the IGFC categorization and appeals process. Access to customer-14 specific information from the California Department of Social Services, such as CalFresh, may 15 also require amendment to existing law, or direct customer consent. It is also conceivable that a 16 verification system could then use other secondary data source in a hierarchical order, which 17 would reduce the incidence of “no matches” in the data. For example, as a secondary step in 18 case there is no FTB or DSS data, the customer of record could be asked to either submit income 19 information or to provide permission to verify income against a secondary database. As a final 20 backstop for the “no-match” population, census tract data could be incorporated to make an 21 educated guess for initial assignment, to help mitigate the possibility that a low-income customer 22

115 Franchise Tax Board, Filing Requirements, available at https://www.ftb.ca.gov/file/personal/residency-status/index.html . 116 CPUC, 2021 Annual Report California Lifeline Program, Program Years January 20219-December 2021, p.18, (April 2022), available at https://www.cpuc.ca.gov/-/media/cpuc- website/divisions/office-of-governmental-affairs-division/reports/2022/2021-ca-lifeline-annual- report.pdf.
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78 would be initially assigned to the highest income bracket, with communications to the customer 1 providing them information on how to appeal if necessary. 2 H. Income Verification and Appeals Process 3

1. Income Verification Ownership and Implementation 4
The Joint IOUs recommend that the income verification process, described in further 5 detail below (including initial assignment, handling any customer appeals, and the periodic 6 refresh process), be conducted by a Third Party under the supervision of the CPUC. It is not 7 practicable or cost-effective for each individual IOU (across the range of large and small IOUs 8 regulated by the CPUC) to implement its own income verification process. Rather, using a 9 single Third Party, supervised by the same governmental entity (as the CPUC has done with 10 LifeLine), allows there to be a consistent statewide approach which should result in increased 11 overall accuracy. Supervision of the Third Party by the CPUC would help to further maintain 12 customer trust that their income information would not be accessed in any way by the IOUs. 13 Furthermore, centralizing statewide income assignment and verification under a single 14 administrator will benefit the customers of all the state’s IOU’s (small and large) by realizing 15 economies of scale, as well as creating a one-stop-shop that consistently uses the same process 16 equally for all. 17
Establishing a single Third-Party entity to conduct the income verification process, 18 supervised by the CPUC, minimizes the cost of implementing the IGFC and limits access to 19 income data, helping to establish customer trust in the process. In contrast, income verification 20 conducted by each utility would result in replication of costs for a similar process. Further, with 21 a Third Party conducting income verification, the State could also leverage the information it 22 receives for other purposes and programs, providing additional benefit to Californians. Indeed, 23 existing income verification programs beyond LifeLine are established or processed at the state 24 10/24/2023 D3 136 of 196

79 level, for similar reasons.117 Although the energy utilities do have some experience running the 1 CARE/FERA programs’ income verification process, that process only verifies a small number 2 of low-income customers each year, and even that is expensive and labor-intensive for a steady-3 state program, let alone a start-up like the IGFC. The Joint IOUs have concluded that the 4 CARE/FERA verification process is not reasonably scalable to provide initial and periodically 5 recurring IGFC verification for the approximately 10.8 million residential electric customers who 6 must receive a new IGFC on their electric bill. As discussed in the section above, scaling current 7 CARE processes to income verify all residential electric customers in the Joint IOUs service 8 territory could cost approximately $97 million, plus added “start-up” costs. The Joint IOUs 9 conclude that doing so would be cost-prohibitive. Moreover, collecting stated income from a 10 customer that applies for inclusion in a discount program like CARE or FERA (and in so doing 11 represents they have qualifying income and consents to a utility verifying this representation) is 12 fundamentally different from collecting and/or accessing personal, private income data from 13 millions of customers who do not seek any discount in order to place those customers on income 14 brackets to determine the fixed charge they will pay. 15 Furthermore, the Joint IOUs have limited experience building income verification models 16 and may only be able to use public income data, which is not available at the household level.118 17 For these reasons, the Joint IOUs recommend the IGFC income bracket assignment and appeal 18 be administered through the CPUC, contracting with a Third Party (or another public agency if 19 needed), rather than trying to develop an entirely new process to be conducted by the Joint IOUs. 20 Finally, initial marketing research conducted by the Joint IOUs revealed that many 21 customers will likely be concerned about IOUs having access to customer income data. The 22

117 Covered California, Government Code Title 22. California Health Benefit Exchange.SB 1208 (Reg.

Sess. 2021-2022), Low-Income Utility Customer Assistance Programs: Concurrent Application Process.
118 The US Census Current Population Survey, available at https://www.census.gov/programs- surveys/cps/data.html and American Community Survey, available at https://www.census.gov/programs-surveys/acs/data.html only provide income data down to the census tract level.
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80 challenges associated with income “verification” are compounded to the extent that a customer’s 1 assigned household income bracket and corresponding fixed charge will depend not only on the 2 named customer’s income, but on the collective income of that customer’s entire household. 3 Establishing a neutral Third-Party to conduct the process will ensure that a trusted, transparent, 4 and secure process for evaluating customer household income and income bracket placement is 5 consistent across the state. 6
For the reasons outlined above, the Joint IOUs reiterate that income bracket assignment 7 and appeal processes should be conducted by a Third Party under the supervision of the CPUC. 8 Although the LifeLine program (which depends on residents seeking out the discount and 9 affirmatively providing proof of income eligibility) does not provide a template for a system in 10 which each household served by a utility is assigned to an income bracket based on household 11 income data collected or accessed without the customers’ involvement, it does provide an 12 example of a verification system that is administered by a Third Party administrator (TPA) under 13 the supervision of the CPUC. As such, the Joint IOUs propose to utilize an administration model 14 here that is similar to the LifeLine program119 to handle IGFC income bracket assessment and 15 appeals, as depicted in Figure III-7 below. 16

119 Consensus and Collaboration Program and Institute for Social Research, California State University, Sacramento, California LifeLine Program Assessment & Evaluation (May 2022), at p. 37, available at https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M478/K367/478367564.PDF . 10/24/2023 D3 138 of 196

81 Figure III-7
Proposed High Level Chart of Entities Involved In Administration and Implementation of Income Bracket Assignment and Appeal Process

1 As depicted in the chart above, the Joint IOUs proposal seeks state funding for income 2 verification to support the policy goals of the IGFC and not adversely impact customer rate 3 affordability. Including funding for the state-administered process of income verification in 4 electric rates would dilute desired impact of beneficial electrification for residential customers. 5 10/24/2023 D3 139 of 196

82 The Joint IOUs propose to collaborate with the CPUC to seek funding for the income 1 verification costs from the State Budget. 2

2. High Level Utility Process Overview 3
The IGFC differs from CARE/FERA because it is not an opt-in rate rider, but a 4 fundamental rate component to ensure that fixed costs are fairly recovered, on an ongoing basis, 5 for the benefit of all customers -- as well as the environment -- by reducing the volumetric rate 6 thus supporting the state’s decarbonization climate action goals through building electrification. 7 Therefore, the Joint IOUs recommend that the IGFC be applied to each and every rate under 8 which all residential customers take electric service from an IOU. Because there are fixed costs 9 to serve every residential customer, and AB 205 requires an income graduated set of fixed 10 charges, there must be some process for categorizing each and every one of the over 10.8 million 11 electric residential households served by the Joint IOUs into appropriate Income Brackets. 12 PG&E, SCE, and SDG&E have approximately 4.9 million, 4.7 million, and 1.3 million electric 13 residential households, respectively. Every one of these residential households must be 14 categorized into the appropriate Income Bracket and then periodically reverified in the future 15 because of income changes. Thus, the type of income verification needed for even a simple 16 graduated fixed charge, at full scale, is a new and complex challenge that will undoubtedly 17 present unanticipated difficulties and unintended effects. At a high level, the Joint IOUs 18 anticipate that there will be three primary components of the verification process: (1) initial 19 income bracket assignment, (2) processing of any appeals and taking any remedial action 20 necessary, and (3) a periodic reverification that makes any necessary changes to income bracket 21 assignments. Each step is described briefly below. 22
a) Initial Income Bracket Assignment 23
During the initial income bracket assignment, customers are placed in the appropriate 24 Income Bracket by the process to be established by the Third-Party, under the CPUC’s 25 10/24/2023 D3 140 of 196

83 supervision. The Joint IOUs are responsible for providing the customer data including customer 1 account information (e.g., name and address, and social security number if available), and the 2 file is used by the Third Party to identify the appropriate Income Bracket, using income data that 3 the Third Party obtains from one or more sources such as FTB and other state entities. The 4 customer’s assignment is then relayed back to the utility, who is responsible for informing the 5 customer of their income bracket placement and providing contact information for assignment 6 appeal with the Third Party. The Joint IOUs stress that in advance of implementation, thorough 7 testing of the income bracket assignment process with real customer data is necessary to 8 demonstrate the accuracy of initial placements and minimize appeals. The testing results could 9 also be used to influence staffing levels for customer support services, such as call center 10 staffing. Further, the Joint IOUs recommend that the Third Party selected by the CPUC for 11 income bracket assignment meet key criteria such as strong data modeling capabilities, a 12 reputation for secure handling of customer data, and accurate results to establish public trust in 13 the process. Information regarding customer outreach and education in this phase is detailed in 14 the Marketing and Outreach, Chapter 5. 15
For existing customers, this process is expected to occur in advance of implementation to 16 give customers adequate time to appeal if their initial income bracket placement is incorrect. 17 New customers would be informed about the income verification process at some point during 18 the move-in process. This process has a more compressed timeline than the initial income 19 verification. The income bracket assignment would have to occur during the first billing cycle 20 and in many cases, the first customer bill cycle is less than a full month. New customers will 21 have to be provided notice of their income bracket assignment so that an appeal can be initiated 22 if needed. From a customer perspective, the ideal solution is to check income during the move-23 in, through regular data exchange with the Third-Party income verifier. The customer could then 24 be immediately informed of their assigned Income Bracket, either over the phone during a call 25 center turn-on, or on the IOU website during a self-service turn-on. 26 10/24/2023 D3 141 of 196

84 It is probable that some populations of customers will not be matched with Third Party 1 data during initial income bracket assignment or during turn-on. For example, there may be a 2 lack of data for new immigrants, customers whose primary residence is in another state or 3 country and who pay no California taxes, or residential accounts that are held by a non-person 4 entity, e.g., a property management company, non-profit organization, or a Home Owners 5 Association taking service for common space lighting. The total number and breadth of these 6 cases is not known. The non-matches are likely higher as a percentage of new move-ins than as 7 a percentage of the existing customer population. The Joint IOUs recommend that the Third-8 Party track and report out on the number of customers that cannot be matched with income data 9 annually. That data should be evaluated to determine what subpopulations exist and if those 10 subpopulations can be identified and assigned an appropriate fixed charge level. The 11 Commission should address the evaluation of this population in a ruling at such time as relevant 12 data become available which is likely within two years of implementation of the IGFC. In the 13 meantime, in cases where a customer is not able to be matched with income data, a secondary 14 data source could be applied. In the absence of such a process, Joint IOUs should assess Income 15 Bracket 3 and inform the customer of the appeal process. In addition, the Joint IOUs 16 acknowledge that some customers may be uncomfortable with any level of data collection, and 17 so an opt-out policy is needed to allow customers their right to privacy. In this scenario, 18 customers opting out would be assessed the highest fixed charge. 19 For a small proportion of customers enrolled in the CARE and FERA programs, Joint 20 IOUs have self-reported income data that has been provided by the customer directly, as long as 21 the customer enrolled based on income, or voluntarily provided income when enrolling via the 22 categorical eligibility method. Additionally, only approximately 6-8% of customers who 23 participate in CARE/FERA programs are subject to income verification through existing 24 processes. As such, Joint IOUs will use Third Party data to assign Income Bracket 1 or Income 25 Bracket 2 fixed charges for customers enrolled in the CARE and FERA programs. If at any 26 time, a CARE/FERA customer becomes no longer enrolled in CARE or FERA the customer will 27 10/24/2023 D3 142 of 196

85 then be assigned an Income Bracket 3 or Income Bracket 4 fixed charge based on Third Party 1 data. Likewise, a non-CARE/FERA enrolled customer who then enrolls in CARE or FERA 2 would be assigned to the Income Bracket 1 or Income Bracket 2 fixed charge. The Joint IOUs 3 recognize that the CPUC’s decision authorizing the IGFC may, once implemented, warrant a 4 CPUC re-examination of current CARE/FERA processes, and recommend that any efficiencies 5 or revisions be discussed in the Low Income Proceeding. 6 b) Appeals Process and Customer-Initiated Income Updates 7 The Joint IOUs’ proposed CPUC process for resolution of customer disputes over their 8 IGFC Income Bracket assignment will provide all residential electric customers an ongoing 9 opportunity to “appeal” and seek what they assert to be a more appropriate categorization of their 10 total household income assignment. The Joint IOUs recommend the customer appeal or dispute 11 resolution process should consist of the following steps: 12

1. Customer contacts the utility through either the call center or the website, and is 13 directed to the Third-Party website or call center to initiate an appeals claim 14

2. Customer claimant provides the Third Party with all requested information, which 15 could include but is not limited to: a complete listing of the legal names of all residents in their 16 household, and for each household member: recent pay stubs, copy of federal tax filings and W2 17 or 1099, affidavit from employer (for cash wages only), finally signed releases from each 18 household member allowing access (for each person) to data from the Department of Social 19 Services, or other such agency 20

3. Third party conducts the appeals process by reviewing the provided 21 documentation and, if necessary, using the releases to obtain any appropriate additional income 22 verification data, and determines whether appeal should be approved or denied 23

4. Third party informs the customer 24

5. Third party informs the respective IOU of the results of the appeal 25

6. IOU adjusts customer’s IGFC Income Bracket within its billing system 26 10/24/2023 D3 143 of 196

86 This recommended appeals process (to be conducted by the Third Party under the 1 supervision of the CPUC) may have three mutually exclusive potential outcomes. 2 The first is a denial determination, with the Third Party deciding that the customer’s 3 initial household income level placement had been correct or that the customer has not submitted 4 sufficient or qualifying information to prove that the assigned income level was incorrect. In 5 such instances, the appeal would be denied, with the customer and their IOU being informed that 6 no change will be made to the customer’s existing, assigned income level. 7 The second potential outcome would be approval by the Third Party if it finds a 8 significant enough change in total household income to warrant a revision to the customer’s 9 previous IGFC Income Bracket placement. In such instances, Third Party would have found that 10 its initial Income Bracket placement (at the time of the most recent IGFC data refresh, or account 11 turn-on) had been correct; nevertheless, the Third Party could still approve the appeal if the 12 available evidence successfully showed that household’s total income had since changed enough 13 to merit placement in a different fixed charge category, going forward. The Third Party would 14 inform the customer that their appeal has been approved and, simultaneously, notify their IOU to 15 update that customer’s fixed charge Income Bracket assignment, as of the next one or two billing 16 cycles after the date of the ruling and notice to the customer and IOU. One to two billing cycles 17 is the standard duration to allow adequate time to process other types of account changes 18 initiated by a customer. Sufficient time is needed for the IOU to process a change in account 19 information reflected in the billing system. The Joint IOUs do not plan to rebill customers for 20 updated income information as this does not constitute a billing error. The Joint IOUs would 21 place the customer onto their updated household Income Bracket prospectively. It is standard 22 practice to receive updated information from a customer that qualifies them for a program or rate 23 and place them into the program or rate on a going-forward basis, per customer request. 24 Examples include 1) a customer applying for CARE for the first time, despite potentially having 25 qualified in the past; 2) a customer buying an electric vehicle, but not sharing information about 26 the purchase and only taking service on an EV rate until months later; 3) a customer installing a 27 10/24/2023 D3 144 of 196

87 smart thermostat, but not signing up for a demand response program until the following year. In 1 these cases, the Joint IOUs do not retroactively place customers on these rates. 2 For efficiency, it is important for the CPUC to consider a limitation on the frequency with 3 which appeals could be made by a given customer. Likewise, because the customer must 4 provide evidence of their updated household income to result in a change to their fixed charge 5 level, then it is important that an account so verified may maintain the new fixed charge level for 6 a certain period of time. To avoid overriding the verified income information, a good option 7 would be to restart the clock for the regular data refresh with the completed appeal. Otherwise, 8 the customer could be caught in an endless appeals loop, which could result in customer 9 frustration. Therefore, any change to the fixed charge Income Bracket pursuant to appeal should 10 be set for a predetermined period (e.g., one or two years). It would be appropriate to apply the 11 same period of time as for the regular data refresh cycle. This will require that an account 12 having gone through appeal and verification be identifiable as such in the Joint IOUs’ billing 13 systems and it will require the Third Party transmit information to the Joint IOUs on the outcome 14 of the appeals process for individual customer accounts. At a minimum, the Third Party should 15 provide the IOU an updated start/end date for the validity of the Income Bracket assignment. 16 The third potential outcome would be that the customer appeal is approved if evidence 17 provided by the customer can demonstrate that their initial household Income Bracket placement 18 at the most recent Income Bracket assignment was already incorrect (e.g., because the income 19 data was incorrect and put them into the wrong category). IOUs have rules governing “billing 20 errors” which are defined similarly as errors by the utility that result in incorrect meter reads or 21 clerical errors that result in the customer being placed on the wrong rate or being charged based 22 on the wrong billing factor or calculation.120 While the Joint IOUs do not consider the situation 23 where a customer was placed on an Income Bracket assignment based on information provided 24 by the CPUC contracted Third Party which was later overturned on appeal to constitute a billing 25

120 See PG&E Rule 17, SCE Rule 17.D and SDG&E Rule 18.C. 10/24/2023 D3 145 of 196

88 error, this assumption should be confirmed in the CPUC’s decision. Furthermore, the Joint IOUs 1 recommend that the CPUC order the IOUs to update their applicable Rules governing billing 2 errors to explicitly state that the situation described above does not constitute a billing error and 3 does not warrant a retroactive bill correction. If the CPUC disagrees and finds that in these 4 instances a rebill is warranted, this type of appeal would require the Third Party to review the 5 information the customer provides with their appeal application seeking to verify it, as well as an 6 additional process for submitting information to the IOUs about the appropriate time period to 7 rebill (e.g., to provide the date as of which the income level needed to be corrected). Depending 8 on the level of accuracy of the income verification data the Third Party uses, this enhanced 9 appeals process to correct an actual income data mistake is likely to be more time- and labor-10 intensive than the other two appeal outcomes. The volume of appeals requests and therefore the 11 operational and financial impact of this third appeals outcome will depend on the accuracy of the 12 underlying data. The higher the quality of the data, the less likely the need for appeals. 13 In general, the as-yet unresolved details about this process that the CPUC will determine 14 in its final decision would likely result in significant impacts on the operational requirements for 15 and costs of such income verification appeals. For instance, if the CPUC decides that accounts 16 with no income data match should be defaulted to the highest fixed charge Income Bracket, then 17 it would seem much more likely that more account owners might initiate the appeals process, 18 which in turn would result in additional processing. In contrast, putting accounts with no data 19 match on Income Bracket 3 could create revenue impacts, but in turn lower appeal volumes and 20 processing costs. This would provide disincentives for customers with high income and no data 21 to provide their true income level. As mentioned above, the Joint IOUs recommend that the 22 population without a data match be analyzed to determine the best approach, and potentially a 23 secondary data source be used for such accounts. Another important determinant of the impact of 24 the appeals process is when customers are informed about the Income Bracket and their ability to 25 update information or appeal. If customers are informed about the ability to appeal at initial 26 10/24/2023 D3 146 of 196

89 assignment and at each change of the Income Bracket, the onus would be on customers to inform 1 the Third Party managing the income verification in a timely manner. 2 c) Periodic Refresh 3
The final component of the overall income verification process is periodic refreshes of 4 household income categorization. During this phase, the Third-Party would re-evaluate each 5 customer’s existing household Income Bracket placement, applying the same method used to 6 identify initial placement, but would incorporate any results of the appeal process that may have 7 resulted in a customer being moved to an alternate Income Bracket as well as any other newly 8 available household income data. As with the initial Income Bracket assignment process, the 9 Third Party being supervised by the CPUC would conduct the analysis and assign Income 10 Bracket to customer accounts. The Joint IOUs would only be provided the refreshed 11 categorization results for all customers, so as to inform customers whose household income level 12 placement has changed. The Joint IOUs recommend considering operational impacts to the 13 IOUs’ respective internal processes, such as billing and call center volume, when determining 14 the appropriate refresh cadence, timing, and cost recovery. 15 I. Currently Projected Costs of Joint IOUs’ Proposal 16 The Joint IOUs anticipate that, under their recommended approach where the CPUC 17 would contract with and supervise a Third-Party income verification process, all of the electric 18 IOUs (small and large) would still incur incremental costs during the income level assignment 19 and appeal processes. Such cost categories include marketing and outreach costs, call center 20 costs, IT and billing operations costs to move customers to a different Income Bracket and revise 21 customer bills based on the appeals process, and administration costs to staff and maintain 22 operations relating to the new income verification process. The majority of these costs are 23 presented in the next two chapters, on Implementation and Marketing chapters, with the 24 exception of staff administration costs. Estimated costs for administration and support costs for 25 10/24/2023 D3 147 of 196

90 each Joint IOU, specific to income verification, under our recommended CPUC-supervised Third 1 Party approach, are listed here in Table III-12 below. 2 Table III-12
Summary of Each Joint IOU’s Internal Costs to Support our Recommended CPUC- Supervised Third-Party Approach to IGFC Income Verification

NOTE: Labor costs cover four years, and include labor for compliance related activities, and anticipated impacts to CARE program
Cost Category PG&E SCE SDG&E Total
Labor $1.6M $0.5M $0.7M $2.8M
J. Anticipated Costs for CPUC-Supervised Third Party Income Verification 3 The Joint IOUs anticipate that the costs for the recommended implementation of income 4 verification under a CPUC supervised Third Party implementer are likely to include such cost 5 categories as: (1) data transfer and potential purchasing and modeling costs, (2) data 6 management and storage costs, (3) systems and business process costs, including the costs of 7 handling appeals, notifying the customer-appellant as well as their IOU of the outcome, and (4) 8 customer outreach and call center costs to handle customer concerns and results of appeals, (5) 9 other resource costs including ongoing program management costs. The initial costs to start-up 10 this new income verification process and apply it to 10.8 million residential electric customers of 11 the Joint IOUs cannot be reliably estimated, however, until more information is known. The 12 Joint IOUs look forward to working with Energy Division and the parties to this proceeding, 13 perhaps in a workshop forum, to further define and research each of the potential costs. 14 As mentioned above, the LifeLine program cannot currently be used as an accurate cost 15 comparison point for the IGFC, for two major reasons. On the one hand, LifeLine program costs 16 may include other cost elements such as customer outreach, etc. that go beyond what we believe 17 would need to be handled for fixed charge income verification and more research is needed to 18 make sure the LifeLine totals can be made apples-to-apples comparable with the IGFC income 19 10/24/2023 D3 148 of 196

91 verification only functions proposed here. On the other hand, the LifeLine program may 1 underestimate IGFC costs because of differences like: (1) an initial IGFC assignment is 2 mandatory whereas LifeLine is an optional rate rider for which a customer application to 3 participate is provided first, and (2) the larger scope including numbers of customers as well as 4 breadth of income types necessary for IGFC income verification seem likely to cause increased 5 overall costs. It is not yet possible to know the precise cost of the much larger scope involved for 6 the IGFC, which must initially verify income for about 10.8 million customers of all Income 7 Brackets, as well as conduct appeals and periodic reverification. At a minimum it could be 8 expected that the statewide IGFC start-up costs of the IGFC would be higher than the current 9 costs for LifeLine. The Joint IOUs also anticipate that startup costs would be more significant. A 10 comparison of existing income verification program costs and how they might be initially 11 estimated to compare to IGFC is shown in Table III-13, below: 12 10/24/2023 D3 149 of 196

92 Table III-13
Comparison of Third Party Income Verification Implementation Costs * See Administrative Law Judge’s Ruling Providing Guidance for Phase 1 Track A Proposals and Requesting Comments on a Consulting Services Proposal (Jan. 17, 2023), Attachment 1, R.22-07-005, Phase 1 Track A:

Income Graduated Fixed Charge Guidance Memo, at p. 10. This $46 million over three years comes out to an average of 15.3 million per year for 1.3 million households, or about $11.80 per household per year. **CARE costs displayed here only include costs relating to applications, recertifications, and verification processes. The CARE program includes additional annual costs in categories such as general administration, IT programming, pilots and studies, measurement and evaluation, regulatory compliance, and marketing and outreach costs. Source: Monthly Reports of PG&E, SCE, and SDG&E on Low Income Assistance Programs for December 2022 available at https://liob.cpuc.ca.gov/monthly-annual-reports/ . ***Source: The 2022-23 Budget: California Food Assistance Program available at https://loa.ca.gov/reports/2022/4532/CA-Food-Assistance-Program-021122.pdf Program Cost per
year
Cost per
Participant
Difference from IGFC
LifeLine $46M for 3
years*
$11.80 IGFC is anticipated to cost more because it is a much larger scale program. Some Lifeline costs
are not comparable due to major program
differences, including that LifeLine only
manages 1.3M customers, while IGFC would be
implemented for about 10.8M electric
customers.

CARE**

1. Application/
Recertification

2. Verification Costs

1. $3.4M

2. $2.1M

1. $2.37

2. $9.40

IGFC is anticipated to cost more due to scale of
program in comparison to CARE. Similar to the
logic above, IGFC requires that all 10.8 M
electric residential customers are transitioned to
the rate structure, resulting in more costs than
the optional CARE rate for X customers.

Further, the CARE program processes have been
refined and improved since the 1990’s. IGFC is
anticipated to have startup costs that are not
reflected in this comparison.

CalFresh CalFresh costs were researched and found to be $2.1 billion from 2020 to 2021,*** but due to the nature of funding, which includes state and federal funding, exact income verification costs were unable to be determined. However, due to the high frequency of required verifications for CalFresh, IGFC costs are anticipated to be lower.

AB 205 did not mention the IGFC costs in its estimated fiscal impact for the bill. 1 However, because the legislature adopted the IGFC out of concern that high electric rates tend to 2 disincentivize adoption of beneficial electrification technologies necessary to decarbonize 3 California’s economy, the CPUC should consider whether the costs of verification should be 4 10/24/2023 D3 150 of 196

93 borne by ratepayers at all, given its likely magnitude. Instead, since the fixed charge is being 1 income graduated for the public purpose of both climate action as well as improved equity and 2 keeping rates affordable, (especially for lower income customers), the CPUC should consider 3 requesting state funding to cover the income verification costs rather than putting the costs into 4 electric rates that would directly undercut the state’s decarbonization and climate action. Further, 5 once this system is established, there will likely be benefits to other Third Parties across the state, 6 such as the State Agencies who are administering State Programs where income verification is 7 required (e.g., CalFresh, Medicaid, LifeLine). 8

1. High-Level Cost Estimates for the Other Major Scenarios Evaluated but not 9 Recommended – In-House IOU Income Verification 10
The Joint IOUs acknowledge that the guidance provided by the ALJ requests that parties 11 provide cost estimates for alternative scenarios to help the CPUC gather a full range of options to 12 compare and evaluate. One primary element of the Joint IOUs’ income verification proposal is 13 that the processes should be conducted by a Third Party and overseen by the CPUC. As 14 discussed in Section F.1 above, there are both cost and policy supporting arguments for this 15 structure. Regarding cost, utilizing the most accurate data set will limit costs associated with 16 handling calls and analysis for appeals. Additionally, utilizing one centralized party for 17 administration would minimize costs as economies of scale are able to be achieved. Furthermore, 18 a centralized administration structure would provide consistency across the state and help enable 19 smaller utilities to implement the IGFC structure. As the CPUC currently oversees a similar 20 process with the LifeLine program, they are the ideal party to oversee this process. 21 As stated above, the Joint IOUs are not able to estimate costs for establishing an in-house 22 IOU income verification process because, despite an exhaustive and ongoing search as described 23 in Section E of this chapter, the Joint IOUs lack access to a data source that would provide an 24 acceptable level of data accuracy. Adopting a data source with significant gaps and/or a high 25 probability of mis-assignment of Income Bracket would likely result in a higher number of 26 10/24/2023 D3 151 of 196

94 customer appeals requiring manual verification of income documentation, thus the potential cost 1 of such a verification process are likely to be higher than the Joint IOUs’ proposal. Although the 2 Joint IOUs currently perform manual verification for a small subset of CARE/FERA customers 3 as described in Section E.5, the process is very costly and not scalable to meet the demands of a 4 process for the entire residential population of the Joint Utilities. 5 Implementation costs are discussed in the Implementation Chapter. Most Implementation 6 costs are not driven by any particular income verification method and as such are unlikely to 7 change significantly based on selection of a method other than the IOU recommended model. 8 Exceptions to this are calls relating to appeals. Those figures currently assume an accurate data 9 set based on state tax data and other state data sources. Should a less accurate data source be 10 used, the costs for handling calls related to the misassignment of Income Brackets and appeals 11 would increase roughly proportionally with the decreased accuracy of the data. 12 K. Timeline for Implementation of Third-Party Income Verification 13 As noted in the CPUC guidance memo, legislation will likely be required to allow the 14 FTB to provide taxpayer data to another entity (such as the CPUC supervising a Third Party 15 implementor) for purposes of IGFC income verification. It is possible that other legislation will 16 be needed to modify existing customer privacy laws as it relates to sharing of income data. The 17 Joint IOUs anticipate that any necessary legislation could still occur in the 2023 legislative 18 session. Assuming legislation is adopted swiftly in 2023, in 2024, any impacted state agency or 19 agencies could issue new regulations and implement any necessary changes to website privacy 20 statements, which could be made effective in January 1, 2025. In 2024, the CPUC could begin a 21 solicitation for a Third Party to perform the income verification function in anticipation of 22 receiving income data from the FTB and other state agencies once it becomes legally accessible 23 in the following year. In 2025, the Third Party would develop processes to receive FTB and data 24 from other state agencies and develop a process to determine household income and associated 25 household Income Brackets. Concurrently in 2025, the Third Party would enter into agreements 26 10/24/2023 D3 152 of 196

95 with the IOUs and begin to work through data sharing protocols and requirements as well as 1 cybersecurity reviews. Work between the IOUs and the Third Parties is likely to begin in 2026, 2 and the remaining steps are discussed in detail in the Implementation chapter of this exhibit.121 3 In Summary: 4
 2023: Legislation for FTB & State Agency Data should be passed. 5  2024: State agencies issue updated regulations and implement changes to privacy 6 statements; CPUC solicits for and contracts with a Third Party implementer. 7  2025: Third Party develops solution. Joint IOUs enter into contracts with the Third 8 Party for IOU implementation functions, such as data sharing. See Chapter 4 Section 9 C.1 Implementation Timing Table IV-17, line 8. 10
 2026: System integration with Third Party begins, see Chapter 4 Section C.1 11 Implementation Timing Table IV-17, line 7. 12

121 The Joint IOUs have worked hard to assess a practicable timeline for implementation of the Joint IOUs’ IGFC Income Verification proposal that balances the desire to expedite with the need to be realistic and cost effective; that timeline is represented in this testimony. However, the Joint IOUs are committed to implementing our respective IGFCs as soon as practicable, and we are open to exploring other practicable solutions for accelerating the timeline proposed above. 10/24/2023 D3 153 of 196

96 IV. 1
IMPLEMENTATION 2
A. Introduction 3
In this chapter, the Joint IOUs describe our plan for implementing the Joint IOUs’ 4 proposed IGFCs, with a focus on: (1) required changes to the Joint IOUs’ respective billing 5 systems, (2) the need for increased customer support staff resources for activities such as 6 managing customer inquiries, and (3) adjustments to customer-facing rate tools. Other features of 7 the Joint IOUs’ implementation plan are covered elsewhere in this testimony but cross-8 referenced in this chapter. For example, the Joint IOUs’ recommended income assignment and 9 verification process is covered above in Chapter 3 (Income Verification), while the overarching 10 marketing, education and outreach (ME&O) plans are described in Chapter 5 (Marketing 11 Education and Outreach), as well as in each of the Joint IOU’s utility-specific separate exhibit. 12 The showings in this Chapter are presented in the following sections: 13  Section B outlines the principles that guide the Joint IOUs’ implementation approach 14 and provides a high-level overview of our proposed plan. 15  Section C describes the significant billing technology infrastructure changes that will 16 be required to implement IGFCs for each of the Joint IOUs’ various residential rate 17 schedules. This section also outlines the Joint IOUs’ recommended approach to 18 transitioning customers as well as updates that will be required to online customer-19 facing tools to incorporate IGFC rates. 20
 Section D describes the Joint IOUs’ proposed coordination activities with Community 21 Choice Aggregators relating to IGFC implementation. 22  Section E describes how the Joint IOUs’ existing customer support processes will be 23 leveraged and, if necessary, amended to assist customers during the transition to 24 IGFC rates. 25
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97  Section F provides cost estimates for implementation activities that are not separately 1 covered in Chapters 3 and 5 (Income Verification and ME&O). Section F also covers 2 estimated costs associated with the Joint IOUs’ proposed Measurement and 3 Evaluation activities that are further detailed in Chapter 2 (Rate Design). 4  Section G describes how the Joint IOUs plan to address the Energy Division’s IGFC 5 Guidance Memo to assess implementation costs associated with other parties’ 6 proposals. 7
The implementation cost estimates for the Joint IOUs proposal, provided in this chapter, 8 may need to be adjusted based on the final rate structure and other programmatic directives 9 provided in the CPUC’s Final Decision. 10
B. Implementation Objectives and Plan Overview 11
The Joint IOUs’ proposals for implementing the transition to rates with IGFCs may be 12 further refined based on additional stakeholder and customer feedback. Currently, our approach 13 seeks to: 14
 Provide customers timely notifications about when the structural IGFC changes will 15 take effect. 16
 Offer customers an opportunity to appeal their assignment to a given Income Bracket 17 before they are transitioned to a rate with IGFCs. 18
 Promote customer understanding of why changes are being made to existing rates. 19  Educate customers about how they will be affected and where they can find 20 information about their IGFC for their current rate. 21  Provide customers information and tools to explore how they may benefit from 22 electrification and reduced bill volatility with the IGFC. 23 The Joint IOUs’ testimony on Marketing Education and Outreach (ME&O), outlined in 24 Chapter 5 below, covers the strategies the Joint IOUs propose to use to ensure timely 25 notifications and promote customer understanding. The proposed ME&O effort will include 26 10/24/2023 D3 155 of 196

98 significant outreach to build customer awareness and understanding ahead of the transition to 1 rates with IGFCs. These efforts will also inform customers about their specific fixed charge 2 household Income Bracket to which they have been assigned and will describe how customers 3 can appeal that assignment prior to being transitioned to the new rates with IGFCs. The 4 Marketing approach outlined in Chapter 5 is further supported by the IOU-specific supplemental 5 exhibits which present cost estimates based on each IOU’s unique circumstances. 6 The Joint IOUs plan to transition all residential customers to rate plans with IGFCs, as 7 described in Chapters 1 (Policy) and 2 (Rate Design). In Section C, below, the Joint IOUs 8 elaborate on our planned transition approach. The following is a brief overview of the Joint 9 IOUs’ transition plan. 10
 Prior to transitioning customers, the Joint IOUs will need to receive the Income 11 Bracket for each customer, which each IOU will utilize to provide its residential 12 customers with information on how they are likely to be impacted by the new IGFC 13 rate design. 14
 Prior to the transition, each IOU will also need to make the necessary billing system 15 and website changes and provide IGFC-related training to our customer contact 16 center personnel. 17
 After the IGFC transition, customers will continue to have access to online tools that 18 enable them to determine their best available rate given their historical usage patterns. 19  On an ongoing basis, customers will receive periodic notifications of any re-20 assignment to a different Income Bracket, along with information about how to 21 appeal that assignment through the Third Party process. 22 C. Billing Information Technology System Changes 23
As is described in Chapter 2 (Rate Design), implementing an IGFC component into the 24 Joint IOUs’ residential electric rates will require structural billing system changes with 25 10/24/2023 D3 156 of 196

99 reprogramming and related testing to modify each of the following residential rate plans to 1 include IGFC components: 2
Table IV-14
Joint IOU Residential Rates Impacted by IGFCs

IOU Rates that will be modified to include IGFCs
PG&E E-1, E-TOU-C, E-TOU-D, EV2-A, E-ELEC
SCE Domestic, TOU-D-4-9PM, TOU-D-5-8PM, TOU-D-PRIME
SDG&E TOU-DR-1, TOU-DR-2, DR, DR-SES, EV-TOU-2, EV- TOU-5, TOU- ELEC

Additionally, the following rate modifiers that may be used in combination with each 3 residential rate plan will also be made available and tested for the new IGFC rates: 4  Legacy NEM 1 and 2 5
 Net Billing 6
 CARE, FERA 7
 Medical Baseline 8
 Critical Peak Pricing (SmartRate for PG&E, Summer Advantage Incentive for SCE, 9 Time of Use Plus for SDG&E) 10
 Summer Discount Plan (SCE), Smart Energy Program (SCE), ACSaver (SDG&E), 11 Summer Saver (SDG&E) 12
Each of the Joint IOUs’ systems will need to interface with the database provided by the 13 Third Party, which will contain information about each customer’s categorization into the 14 appropriate household Income Bracket.122 Each IOU can then use this data to update its billing 15

122 The Joint IOUs expect that, due to customer privacy requirements, the data provided by the Third Party will only indicate which of the four household income categories a customer’s electric service account was assigned.
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100
system(s) and other tools to reflect the household Income Bracket assignment of each customer 1 so the account is charged the corresponding monthly fixed charge amount. The approach for 2 developing this database is described in Chapter 3 (Income Verification). 3

1. Implementation Timing 4
The Joint IOUs’ Billing Implementation timelines are shaped by dependencies with the 5 Third Party income verification process described in Chapter 3, as well as with the ME&O 6 efforts set forth in Chapter 5 of the Joint IOUs’ IGFC testimony. Some workstreams can be 7 completed in parallel but dependencies between the workstreams put constraints on when the 8 IGFC rates can go live in each of the Joint IOU’s billing systems. The Joint IOUs estimate a 9 minimum of 32 months from the time at which contracting and cyber security review have been 10 completed between each IOU and the Third Party, and the “go live” date on which customers 11 will begin to receive bills with IGFC rates.123 The following key implementation workstreams 12 are interdependent with income assignment/verification and ME&O: 13  Contracting and cybersecurity reviews must be completed with the Third Party 14  Income assignment data must be integrated with the Joint IOUs’ billing systems and 15 tested (estimated to span 12-18 months for integration plus another 1-2 months for 16 testing) 17
 Modeling of customer bill impacts must be completed for IOUs who plan to send 18 customers this information in their pre-launch customer notifications (estimated to 19 span 1-3 months) 20
 Customer notifications must be sent out enough months ahead of the initial launch of 21 IGFCs on bills to allow customers to respond and for the Third Party to resolve 22 appeals (estimated to span 6 months) 23

123 Timing and costs for PG&E to make necessary changes to its billing system may vary due to its multi-year billing modernization initiative. Please see PG&E’s supplemental implementation chapter for more details.
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101
Table III-12 illustrates a preliminary timeline for billing implementation and key 1 dependencies. Due to uncertainty about when the Third-Party income assignment and 2 verification system will provide household income bracket assignments, the Joint IOUs are 3 showing the timeline with reference to month “t” which indicates the month in which the IGFC 4 goes live in the Joint IOUs’ billing systems and customers begin receiving bills that show the 5 IGFC rate component and the reduced volumetric rate. 6
The Joint IOUs believe that income assignment information must be available and billing 7 calculations must be coded into the Joint IOUs’ billing systems roughly 12 months before the 8 “Go Live” month when customers would begin receiving bills under IGFC rates (line 1 in Table 9 IV-16 below). This would allow integration of the income assignment data with Joint IOUs’ 10 billing systems (line 6), which would then allow rate modeling of what customers’ impacts 11 would be on the IGFC rates to enable such information to be included if and as appropriate in the 12 Joint IOUs’ pre-launch notifications sent to customers. These notifications will be staggered to 13 avoid overloading the Joint IOUs’ contact centers with customer inquiries triggered by the new 14 IGFC changes set forth therein. The exact timing for each utility will likely be different for each 15 IOU based on system capabilities and customer preferences. 16 The integration of income assignments into the billing system, as well as other needed 17 system changes, is estimated to take about 12-18 months. This is based on discussions with the 18 Joint IOUs’ Information Technology (IT) organizations as well as on prior experiences in system 19 integration with Third Party vendors when a two-way data feed is required. This effort would not 20 begin until contracting and cyber reviews have been completed with the Third Party which is 21 estimated to be the end of 2025 as described in the Income Verification Chapter Section H. This 22 timeline is an estimate across all three utilities and may increase or decrease in duration for a 23 given IOU, based on the time required for that IOU to execute these steps. Timing may also be 24 impacted by other unknowns related to implementation of the income verification process. 25 10/24/2023 D3 159 of 196

102
Table IV-15
Implementation Milestones
Line Month Milestone/Activity Dependency (Line)
1 t minus 0 (t-0)
months
Launch date when customers’ bills start
separately showing the IGFC and reduced
volumetric charge
3 2 t-6 through t-1 Third party processes customer appeals 3 3 t-6 through t-3 Customer notifications sent 4
4 t-9 through t-7 Customer impacts are modeled and customer communications are prepared
5 5 t-11 through t-10 Complete integration and testing of income assignment data and billing system changes
6 6 t-12 Income assignment data from Third Party is
fully integrated into IOU’s billing system(s)
7 7 t-31 through t-13 IOUs Implement IT changes needed to restructure rate calculations and bills to show
the IGFC line item and integrate income
assignment data flow from Third Party
8 8 t-32 Contracting and cybersecurity review
completed with Third Party
n/a

2. Approach to Transitioning Customers 1
Once all of the required prerequisites have been accomplished, including: (1) Joint IOUs’ 2 billing system changes are in place, (2) household income categorizations have been prepared by 3 a Third Party for all customers and transmitted to each IOU, and (3) appropriate pre-transition 4 ME&O has been accomplished, the Joint IOUs will transition their residential customers to IGFC 5 rates during a time of year when customers’ attention is less likely to be diverted to higher bills, 6 weather events, or potential outages. This timing aims to reduce the chance that the impact of the 7 transition to IGFCs could be confounded by other changes that also affect the customer’s total 8 bill. 9
At the time an IOU’s customers are transitioned to a rate with an IGFC, Net Energy 10 Metering and Net Billing customers will retain their banked bill credits accrued prior to the 11 addition of the IGFC, and these bill credits will carry forward through the end of their relevant 12 10/24/2023 D3 160 of 196

103
true-up period. By design, rate changes or changes to an existing rate will not trigger the relevant 1 true-up period to end prematurely in the billing system. 2 Customers will be transitioned to the updated version of the same rate schedule on which 3 they currently take service (like for like), after it is modified to include the new IGFC line item 4 as well as the reduced volumetric rate. This avoids the customer having to navigate changes to 5 other elements of their rate structure, while also understanding the IGFC changes. The Joint 6 IOUs’ cost estimates assume that the transition to new rates will occur during one billing cycle 7 over approximately one month, with customers transitioning on their billing cycle date, which 8 varies by customer. However, the exact rollout approach is still being reviewed. 9

3. Updates to Current Customer-Facing Tools 10
The Joint IOUs currently provide residential customers access to online rate analysis 11 tools that help customers determine their best rate option. The tools leverage a given customer’s 12 latest year of historical electricity usage to determine what their bill would have been on 13 alternative rates and show customers the lowest cost rate. Current customer-facing tools will be 14 updated with IGFC rates to help customers determine their best rate option once they have 15 transitioned. Also, PG&E and SCE offer an online solar calculator to our customers, where 16 customers can use their last year’s usage history to examine the economics of investing in solar. 17 This tool will also be updated to reflect the changes in rate structure resulting from the final 18 IGFC decision. 19
SCE and PG&E also offer budget assistant tools that helps customers predict their 20 upcoming bill amounts. All of the Joint IOUs provide Bill-Forecast and/or Bill-to-Date 21 capabilities for their customers. These tools will likewise have to be updated. 22

4. New Tools 23
To support decarbonization through beneficial electrification, the Joint IOUs propose to 24 explore developing additional tools during the roll-out of IGFCs, such as adding technology 25 modeling to existing rate analysis tools or offering calculators that estimate the price of energy 26 10/24/2023 D3 161 of 196

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for an electrification technology compared to non-electric technologies. Our current cost 1 estimates do not include the cost of implementing and maintaining such tools. 2 D. Coordination with Community Choice Aggregators 3
The Joint IOUs propose to coordinate with Community Choice Aggregators (CCAs) 4 about the rate design changes adopted by the CPUC. As is explained in Chapter 2 (Rate Design), 5 generation costs will not be included in the IGFCs so CCA generation rates will not be directly 6 affected. Joint IOUs will also communicate with the CCAs in their service areas about IGFC 7 transition plans and monitor any CCA transition activities that might occur simultaneously so 8 that customer communication about the multiple changes to their billing is considered. 9 E. Customer Support Resources - Contact Centers 10
Each of the Joint IOUs has customer contact centers that collectively fielded about 12.5 11 million customer calls per year on average between 2019 and 2022 (PG&E fielding about 6.4 12 million customer calls per year, SCE fielding about 4.5 million, and SDG&E about 1.6 million 13 calls per year). The majority of these calls are related to billing and rates which, as a category, 14 generally have the highest average handle times among residential calls. The Joint IOUs 15 anticipate a considerable increase in customer inquiries before, during, and after deployment of 16 the IGFC rates because the changes required for the IGFC are a new rate framework that 17 customers will have to navigate. The Joint IOUs’ proposal will seek to minimize customer calls 18 through use of self-service Interactive Voice Response software and online resources to provide 19 information that may respond to the customers’ questions without requiring them to talk with a 20 live customer service representative. Even with those measures, the Joint IOUs expect that the 21 volume of calls coming into our call centers will increase, with the magnitude of increase 22 dependent in part on how accurate the household Income Bracket assignments are, which will be 23 influenced by the type of data available used in the process the CPUC ultimately adopts. An 24 approach like the Joint IOUs’ proposal to have an independent Third Party, supervised by the 25 10/24/2023 D3 162 of 196

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CPUC, that uses highly accurate data sources will likely result in fewer misassignments and 1 resulting customer appeals than an approach that depends on less reliable income data sources. 2 Based on the income assignment approach described in Chapter 3 (Income Verification), the 3 Joint IOUs expect that calls would increase significantly in the period before, during, and shortly 4 after deployment of the fixed charges. Each of the Joint IOUs has provided current estimates of 5 the associated costs of handling increased calls if the Joint IOUs’ IGFC rate and process 6 proposals are adopted without modification. Deviations from the Joint IOUs’ proposal have the 7 potential to increase these costs significantly. A summary of PG&E’s, SCE’s, and SDG&E’s 8 respective IOU-specific information can be found in each of their supplemental exhibits SCE-01, 9 PG&E-01, and SDG&E-01. 10
F. Costs 11
The Joint IOUs’ current cost estimates associated with our proposed income verification 12 approach are described in Chapter 3 (Income Verification). Costs associated with the Joint IOUs’ 13 ME&O approaches are covered in Chapter 5 (Marketing, Education & Outreach). In this 14 Implementation chapter, the Joint IOUs outline and provide cost estimates for other costs 15 associated with implementation. For convenience, this Exhibit presents as Appendix C, a table 16 reflecting the currently estimated IOU costs under the Joint IOUs’ proposal for Implementation, 17 IOU Income Verification, and ME&O. 18

1. Implementation Costs 19
Key implementation costs include IT billing system changes and revisions to rate 20 calculations that support a number of customer-facing tools. Significant costs are also likely to 21 be incurred by the Joint IOUs’ contact centers, which will need to be appropriately staffed and 22 trained to field questions about how and why the IGFC-related changes are being made to 23 residential rates, as well as address customers’ questions about household Income Bracket 24 10/24/2023 D3 163 of 196

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assignment and verification. Table IV-16 below presents the currently estimated costs, by Joint 1 IOU, for the anticipated major cost areas: 2
Table IV-16
Estimated Implementation Costs by IOU

Cost per IOU (in thousands of dollars)
Cost Category PG&E SCE SDG&E Joint IOUs’ total
Billing IT Implementation including
incorporation of income data into
billing system and coding and testing
of new rates
$5,000 $5,900 $6,500 $17,400
Updates of customer-facing online rate
tools and Distributed Energy Resource
calculators
$1,010 $59 $1,200 $2,269
Contact Center Training and
Operations (in the year prior to
deployment and two years after
deployment)
$15,910 $9,900 $5,138 $30,948
Program/Project Management of
Implementation
$2,400 n/a $1,560 $3,960
Total: $24,320 $15,859 $14,398 $54,577

These estimates are based on the Joint IOUs’ implementation proposal, and they do not 3 reflect costs associated with other approaches to implementation, or the costs resulting from the 4 CPUC’s 2024 final decision, if it differs from the Joint IOUs’ opening testimony proposal herein. 5 The Joint IOUs request the authority to file an Advice Letter, within 90-days after the CPUC 6 issues its Final Decision. In this filing, the Joint IOUs will provide more detailed implementation 7 costs for which we will seek balancing account recovery, as described in Chapter 6 (Cost 8 Recovery). 9
Exhibits (PG&E-01), (SCE-01), and (SDG&E-01, et seq.) provide more detail on each of 10 the Joint IOUs’ currently expected individual, IOU-specific Implementation cost estimates. 11 Differences between costs and timing among the Joint IOUs are primarily explained by the 12 following: 13
 SDG&E serves fewer customers than SCE and PG&E, thus SDG&E’s customer-14 specific costs can be expected to be lower. 15
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 SCE believes it has sufficient resources for Program/Project Management to 1 implement the Joint IOUs’ proposal but reserves the right to reassess costs once 2 the final decision’s approach is adopted. 3

2. Measurement and Evaluation 4
To evaluate the effectiveness of the transition to residential rates with IGFCs, the Joint 5 IOUs propose that the CPUC provide sufficient funding to assess whether the IGFC transition 6 has met the policy objectives outlined in the Assigned Commissioners Phase 1 Scoping Memo 7 for R-22-07-005 that are relevant to income-graduated fixed charges. One of the Joint IOUs 8 should be tasked with leading the Measurement and Evaluation (M&E) effort for all affected 9 IOUs. 10
The policy objectives to be evaluated include: 11
 Goal (b) make electric bills more affordable and equitable 12  Goal (d) enable widespread electrification of buildings and transportation to meet the 13 state’s climate goals 14
The Joint IOUs’ proposed process for assessing and evaluating the IGFCs’ ability to meet 15 the goals set forth in the CPUC’s final Track A decision can be found in the Rate Design 16 Chapter. 17
G. High-Level Estimates of Timing and Cost for Other Anticipated Proposals 18 The Energy Division’s January 17, 2023, Guidance Memo states that “IOUs should 19 provide estimated timelines for different implementation options that the IOUs anticipate that 20 other parties will propose.”124 It is very difficult to anticipate and understand what other parties 21 are recommending without having seen the details of what they actually propose in their 22 concurrent Opening Testimony due April 7, 2023. The Joint IOUs have been informally 23

124 Administrative Law Judge’s Ruling Providing Guidance for Phase 1 Track A Proposals and Requesting Comments on a Consulting Services Proposal (Jan. 17, 2023), Attachment 1,R.22-07-005, Phase 1 Track A: Income Graduated Fixed Charge Guidance Memo, at p. 10. 10/24/2023 D3 165 of 196

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communicating with a number of stakeholders as we have worked to develop our Opening 1 Testimony, but parties have still been in the process of determining their specific proposals. The 2 Joint IOUs intend to review all proposals as quickly as possible, as well as conduct discovery to 3 gain clarification through data requests, if needed. Additional information evaluating and 4 comparing high level impacts of their proposals, including its impacts on implementation costs, 5 will be provided in Reply Testimony, to the extent practicable.6 10/24/2023 D3 166 of 196

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V. 1
MARKETING EDUCATION & OUTREACH 2
A. Introduction 3
The Joint IOUs recognize that Marketing, Education, and Outreach (ME&O) is 4 fundamental to gaining customer awareness, understanding, and acceptance of the IGFC. 5 The Joint IOUs’ ME&O approach is constructed with the understanding that energy costs 6 are a disproportionate burden on lower-income families, with households across California 7 struggling to pay their bills. It is an opportunity to educate customers about how implementing 8 the IGFC will help address equity and affordability. Additionally, the IGFC sets the stage for 9 beneficial electrification in California by reducing volumetric charges for all residential 10 customers. Effective communication with customers before, during, and after introducing the 11 IGFC for electric service will be critical to improving customer understanding and reducing 12 complaints. 13
The overarching ME&O approach outlined in this chapter aims to demonstrate how the 14 Joint IOUs propose to test, adjust, and inform customers that the IGFC will help cover 15 incremental costs associated with providing electricity in a less regressive, more efficient 16 structure. The expected outcomes of the ME&O are awareness, understanding, and acceptance. 17 B. Research Insights 18

1. PG&E 19
In fall 2022, PG&E hired C-Space to conduct initial qualitative research exploring 20 customer reactions to messaging and positioning of descriptive language for a residential Fixed 21 Charge (PG&E’s 2022 Messaging Research). This initial research also identified customer-22 facing names for this rate component that would be intuitive to customers and accurately 23 represent the intent underlying AB 205’s directives to the CPUC requiring it to approve 24 conforming residential IGFCs for all IOUs by mid-2024. 25 10/24/2023 D3 167 of 196

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More specifically, PG&E’s 2022 Messaging Research set out to understand: 1

1. Customer perceptions of a generic illustrative fixed charge rate component, and 2 whether their perceptions change based on potential impact to their bills; 3

2. Reactions to different amounts for this charge, as well as the reaction to the charge 4 varying based on household income categories; 5

3. How clearly did customers understand the exploratory descriptions, and what did 6 customers want to learn about the IGFC; 7

4. Best way(s) to message this charge for understanding and acceptance; 8

5. Through what communication channels would customers prefer to receive 9 information to learn about the IGFC; 10

6. Recommendations on what customer-facing name customers prefer for referring to 11 Fixed Charges. 12
PG&E’s 2022 Messaging Research was conducted in English and Spanish and included 13 both CARE and non-CARE customers. Methods included video focus groups of high, 14 medium, and low-income customers across hot and cool climate zones (three one-hour video 15 focus groups, 4-5 participants per group), in-depth one-to-one interviews in hot climates of 16 Spanish speakers, and an online survey (284 participants). 17 a) Stimuli 18
Customers were given a written description to introduce the concept of a Fixed Charge 19 based on an early generic understanding of a potential implementation. The description was 20 intentionally written in a straight-forward, factual manner to monitor initial customer reactions, 21 understanding of basic concepts, pinpoint areas of potential confusion or need for further clarity 22 of details (information we may not have today but that will come later in this process). The 23 research purposefully did not initially state the potential dollar amount(s)of residential fixed 24 charges, to allow early discussions to probe for what preconceived amounts could be in each 25 10/24/2023 D3 168 of 196

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customer’s mind. The initial descriptive statement, without yet putting forth any fixed charge 1 dollar amount, was provided as follows: 2
3 PG&E’s 2022 Messaging Research also probed customers on what potential names for 4 the charge might be considered, and provided the below examples, in addition to “Fixed Charge” 5 to gain reaction as to which one is most descriptive: 6  Basic Services Charge 7
 Customer Services Charge 8
 Base Charge 9
 Standard Charge 10
 Shared Services Charge 11
b) Key Findings 12
Results from PG&E’s 2022 focus groups and survey provided clear direction on how to 13 evolve messaging and outreach to achieve greater customer understanding and acceptance. 14 Highlights include: 15
 Initial reactions to the IGFC involve confusion and distrust. Customers had a lot of 16 questions about how the charge would work and the impact it would have on their 17 bills. 18
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 Customers from all income groups expected their bills to increase with the 1 implementation of the IGFC 2
 Customers presumed the IGFC amount may go up to $20 or $25 dollars at most and 3 reacted negatively to any amount above this range. 4
 There is a general concern that the IGFC would not incentivize conservation. Many, 5 especially CARE customers in the study, felt the IGFC would be unfair to those who 6 intentionally try to minimize their energy usage. 7
 The income-based structure doesn’t sit well with most customers, as many are 8 confused about whether or how PG&E might get such income information as 9 well as perceived it as unfair. There should be clear and open communication 10 before implementing the IGFC. Customers would like to have data to 11 understand the calculations, real examples of what the charge covers, bill 12 mock-ups, and comparisons with the previous way of charging. 13  Email and bill inserts are preferred channels of communication, but some customers 14 point out that a personalized approach is also needed. They would like to have 3-6 15 months of notice before the new residential IGFC first appears in their bills. 16  When asked to provide feedback on potential names for the charge, customers most 17 preferred “Basic Services Charge,” followed by “Base Charge.” Customers said the 18 terms “Basic” and “Base” helped them identify that the charge represents the 19 foundational costs to maintain and operate their service, which is completely separate 20 from their energy usage. These terms also helped them understand that all residential 21 customers would experience a fixed charge. 22
 PG&E’s 2022 Messaging Research indicated that moderate- and higher- income 23 customers understand and are even in favor of lower income customers not having to 24 bear the higher portion of this charge. However, their initial reactions to the concept 25 were not positive and they appeared to need further information, with real examples 26 of before and after bills, to increase understanding and acceptance. 27 10/24/2023 D3 170 of 196

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2. SDG&E 1
In the first quarter of 2023, SDG&E hired Travis Research to facilitate qualitative 2 research to help inform the ME&O strategy and implementation. The primary goals of the 3 qualitative research were to understand customers' current rate structure better, gauge their 4 reactions regarding an IGFC, and gain initial feedback on messaging areas. A total of 22 in-5 depth interviews lasting up to one hour each was conducted with participants representing the 6 following customer segments: low income, moderate-income, and high-income, as well as 7 Spanish-speaking and existing solar customers. 8
SDG&E's key Q1 2023 research findings showed that: 9
 Participants assumed the IGFC would automatically result in higher bills; 10  There was concern about increased usage being more affordable, with several 11 mentioning it goes against the conservation message that they've been receiving for 12 years; 13
 Email was the preferred communication channel, slightly higher than direct mail 14 followed by the SDG&E app; 15
 Participants indicated a preference for three- to six-months' notice before 16 implementation of the IGFC, although some thought that a month might be sufficient; 17 and 18
 Several participants felt the dollar differential between the basic service fees for low-19 income vs. high-income was too large. This further fueled the opinion that this 20 structure is unfair to customers who make more money; although some were more 21 open to the concept of higher-income households paying more. 22

3. SCE 23
In the first quarter of 2023, SCE conducted an online survey of nearly 700 residential 24 customers using the cloud-based platform, Alida, about perceptions of a fixed charge. Insights 25 10/24/2023 D3 171 of 196

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from SCE’s Q1 2023 Research generally align with the research insights from studies conducted 1 by PG&E and SDG&E. 2
The concept of an IGFC was not well-received by residential customers. The charge 3 evoked negative feelings of worry, helplessness, anger and/or confusion, with 66% feeling that it 4 was not acceptable for SCE to have access to their income data and that they believed it was 5 effectively a tax, and another way for SCE to make higher profits. 6 Other relevant insights from SCE’s Q1 2023 Research include: 7  Customers would be more likely to support a fixed charge based mainly on their 8 usage instead of solely on their income level (54% support vs. 25% oppose this 9 option). 10
 Overall, customers believed it was not fair that the fixed charge be based on their 11 income, but instead, it should be based on usage. For example, energy conscious 12 lower users felt they were being penalized through fixed charges. Also, they stated 13 they already pay high property taxes, and believed that the IGFC would increase their 14 financial burden. 15
 When asked if customers would seek out additional information on the charge, only 16 13% said no. 17
C. Joint IOU ME&O Proposal’s Objectives 18
The objectives for the Joint IOUs’ proposals for ME&O outreach are to: 19  Help customers understand that the way they have been charged for electricity will be 20 changing, why and when the new structure is being applied, what the funds will be 21 used for, how their bill may be impacted, and helpful ways to manage energy costs; 22 Inform existing residential customers of their household’s income-based 23 categorization and provide a way for customers to dispute their income bracket 24 assignment if incorrect 25
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 Explain how the IGFC will be a separate line item shown on their bill rather than a 1 change in rate design; educate that the new IGFC charge line item on their bill had 2 previously been embedded in their volumetric energy use charge (and how all 3 customers’ volumetric charge will be going down once the fixed costs are relocated to 4 a separate line item); 5
 Assure low-income CARE and FERA customers that their assistance program 6 discounts will not be affected by the IGFC, as well as that after the shift to a separate 7 IGFC line item, they may actually see lower bills as a result; 8  Craft targeted messaging for subgroups more likely to need specialized outreach, as 9 discussed below; 10
 Explore the use of clean energy and electrification messaging, while explaining that 11 the pricing structure encourages adoption of technologies that allow expanded use of 12 lower-priced, cleaner, more plentiful electricity and reduced use of GHG-emitting 13 fossil fuels; 14
D. Lessons Learned from Residential Time-of-Use Transition Inform IGFC Outreach 15 Strategies 16
Recent IOU experiences transitioning millions of residential customers to default Time-17 of-Use (TOU) rate plans provide useful insights to help inform customers, calm potential 18 backlash, and make sure vulnerable customers are included in the conversation. Key lessons 19 from the TOU default TOU transition, as shown in Table V-17 below, include communicating 20 with customers early and often about how the change will impact their bills, what the IGFC 21 covers, the reasoning behind it, and how it will create a more equitable, cleaner energy future. 22 10/24/2023 D3 173 of 196

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Table V-17
Useful Lessons from Residential Default TOU Transition to Inform IGFC The Joint IOUs took RROIR’s default TOU transition lessons, summarized above, and 1 applied them to come up with the following IGFC outreach strategies: 2  Integrate and coordinate general market communications with targeted direct 3 channels, to create awareness, understanding, and acceptance; 4  Leverage the IOU’s network of CBOs, earned media, and external stakeholders, to 5 help increase awareness and understanding of the IGFC; 6  Use customer segmentation to create personalized, tailored communications; 7 10/24/2023 D3 174 of 196

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 Take a multi-touch approach, with targeted marketing and outreach, to drive 1 awareness across all customers; and 2
 Strategically integrate messaging into other marketing efforts, as appropriate. 3 E. Plans to Refine Outreach Plans Based on Findings from Additional Research 4 The Joint IOUs plan to conduct additional research prior to the start of outreach to 5 continue to learn from customers about their preferred approach to IGFC messaging and 6 education, so as to enable parties to further refine their marketing, education and outreach using 7 the customer voice. We will share research approaches and outcomes to align on results, and 8 implementation of these learnings on customer outreach. Areas of research may include: 9

1. Refine and validate language that clearly communicates the intended message; 10

2. Identify areas of potential confusion that may require further clarification 11

3. Validate materials and tools to address specific customer needs; 12

4. Learn when and how to differentiate messaging by the three phases and by bill impact 13 and customer segment; 14

5. Identify clear and well-received terminology to use in customer-facing 15 communications when referencing the IGFC; and 16

6. Test and validate specialized messaging necessary for customers in Income Brackets 17 1-4, as well as for solar customers segments within the various Income Brackets, 18 among other targeted customer segments as appropriate. 19 F. Target Audiences 20
The Joint IOUs propose to use bill analysis as well as IGFC household income category 21 assignments (once the Third Party makes that list available) to determine target audiences as well 22 as to assess impacts and determine customer segments. Customer segments may include low-23 income, moderate- and high-income/low-usage users, as well as solar customers, and segments 24 large enough to warrant in-language communications, among others. These segments may 25 10/24/2023 D3 175 of 196

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require the Joint IOU’s proposal here to be adjusted for any further incremental outreach efforts 1 and specialized messaging found to be appropriate (as it cannot yet be included here). If so, such 2 additional specialized messaging for segment-specific communications would need to be tested 3 and validated through additional research as described in section F above. 4 G. Rollout and Implementation 5
To effectively support ME&O efforts, customer communications are planned to begin 6 approximately six months ahead of the Joint IOUs’ transition showing the IGFC on customers’ 7 bills. The Joint IOUs propose multiple touchpoint communications in a phased approach, with 8 additional rate communications after the transition. In addition, outreach to external stakeholders 9 and community leaders, including elected officials, Community-Based Organizations (CBOs) 10 and media may start as soon as the CPUC’s final decision on the IGFC is issued. 11 Similar to the residential default TOU transition, the IOUs’ customers will need time to 12 become aware of the new IGFC rate structure, understand what costs are being pulled out of the 13 volumetric rate and charged separately through a new fixed charge line item, as well as 14 understand how this structural change will likely affect their own household electricity bills. 15 Therefore, the Joint IOUs propose to use a phased approach when communicating with 16 customers, to achieve customer awareness, understanding, and acceptance. This approach will 17 inform the timing of tactics and allow for progression of the messaging and outreach channels. 18 Phase 1 – Awareness: Setting the context for what the IGFC is, why it is being 19 implemented, and when it will take effect; 20
Phase 2 – Inform: Further emphasis on individual bill impacts including the income 21 category a customer has been assigned, and the income verification and appeals process; 22 these materials will also reinforce available online resources where customers can get 23 more information; and 24
Phase 3 –Engagement: After IGFC implementation, outreach will focus on the total bill 25 experience. Ongoing rate education will reinforce the desired behaviors to support the 26 10/24/2023 D3 176 of 196

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state’s decarbonization goals, along with the cost saving benefits of shifting usage out of 1 the higher cost and higher emissions TOU peak times, as well as promote other bill 2 management solutions. 3
Table V-18 (below) outlines three sample personas and touchpoints for each phase as 4 outlined above to help bring to life how a customer may experience education and outreach. 5 Actual customer touchpoints may vary depending on the customer segment, service territory and 6 any final directives provided through this proceeding. 7 10/24/2023 D3 177 of 196

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Table V-18
Joint IOUs’ Proposed Phased IGFC Communication Sample

H. Messaging Phases and Customer Journey 1
The Joint IOUs plan to differentiate messaging by the phases noted above, as well as by 2 bill impact and customer segment once it is tested and validated through additional customer 3 research. 4
In Phase I (Aware), all customers will receive base messaging that provides over-arching 5 information about the IGFC. Early messaging will communicate how the charge will apply to all 6 residential customers. Communications will detail the various fixed charge Income Brackets as 7 well as emphasize why the change is occurring. 8
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Marketing materials will be developed to illustrate what the proposed IGFC means for 1 customer bills, and to engage stakeholders, such as media, elected officials, and CBOs early in 2 the process. The change in the way customers are billed could easily be misunderstood unless 3 the narrative is communicated in advance and proactively supported by examples of customer 4 bill outcomes. 5
Building on Phase 1 (Aware), Phase 2 (Inform) will expand to clearly explain what to 6 expect when and where to find personalized information. This is a key step toward educating 7 customers about the proposed IGFC as the focus evolves to the benefits most customers will gain 8 from the rate structure, including helping to achieve California’s climate goals and increase 9 electrification. Messaging may also include how the IGFC helps low-income customers, 10 provides more transparency in electric bills, and makes bills more predictable. 11 The Joint IOUs also plan to create representative scenarios with representative amounts 12 of monthly usage combined with CPUC-adopted fixed charges for the various IGFC Income 13 Brackets. This will also include a comparison of several typical bills before and after the IGFC 14 is applied. These scenarios will include a breakdown of the IGFC and the volumetric usage 15 charge to illustrate how the costs are not new but have only been reallocated. As with other 16 major changes to rates or bill structures, it will be critical to steer customers toward tailored 17 information about how it may directly affect their own bills. This information will be provided 18 on the Joint IOUs’ websites, in customer notifications, as well as through other channels detailed 19 in the Tactics section below. 20
Once the IGFC has been implemented, the Joint IOUs propose to focus on Phase 3 21 (Engage) to continue educating customers about energy-saving and efficient electrification 22 behaviors and actions they can take to help manage their bills. Messaging may promote energy 23 management solutions, such as available incentives and rebates, building and transportation 24 electrification and Time-of-Use, and assistance programs. 25 10/24/2023 D3 179 of 196

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I. Integrated Campaign Tactics 1
The Joint IOUs plan to use various outreach channels to form a holistic, integrated 2 education and outreach campaign to support IGFC implementation. Tactics may include direct-3 to-customer messaging, broad customer outreach, and paid channels, as well as IOU-owned 4 channels. In-language materials will be developed based on target audience, and may vary, 5 depending on each IOUs’ unique service area’s demographics. 6 Integrated campaign tactics may include: 7

1. Direct-to-Customer: Direct Marketing tactics will be part of specific, targeted 8 campaigns that will leverage customer segmentation data. Timing scenarios are for illustrative 9 purposes and may change due to exact implementation and operational requirements. These 10 tactics include: 11
a. Direct Email or Direct Mail: Direct channels will be used to inform customers 12 of the IGFC and will drive them online to learn more and find applicable bill examples that apply 13 to their households. This approach will help inform customers and satisfy their need to 14 understand how the IGFC will affect their electric bills. As with the TOU transition, the Joint 15 IOUs propose to deploy multiple touchpoints throughout the customer journey. The Joint IOUs 16 anticipate direct customer outreach may begin up to 180 to 90-days prior to the transition, to 17 notify them of their IGFC bracket and the appropriate cadence and response channels for 18 submitting bracket assignment change requests. Each IOU will adopt their own plan, depending 19 on the details of the final decision, the rate structure, and the IGFC implementation timing. 20 (1) For increased cost efficiencies, the Joint IOUs plan to adopt an “email 21 first” communication channel approach, in which customers will be contacted by email if they 22 have email addresses on file. Direct mail will be used for those customers without email 23 addresses on file. 24
b. Bill Package: Additional opportunities to directly reach customers about the 25 IGFC include leveraging customer bill inserts, “onsert” messages, and/or on-bill messaging at 26 10/24/2023 D3 180 of 196

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least 60-days or one to two bill cycles prior to implementation and throughout the first transition 1 year. These tactics will help educate customers at the point at which they may be the most 2 confused. A short explanation can guide customers to a website for more in-depth information. 3

2. Web Presence: Many customers will go online as the primary source of 4 information about the new IGFC. The Joint IOUs’ websites will provide both higher-level 5 explanations of the IGFC as well as more in-depth information of the services it covers and the 6 illustrative impacts it may have on bills. The web is an important channel to support and educate 7 as many customers as possible, when it is convenient for them to self-serve information. It is also 8 critical to help the Joint IOUs reduce the volume of follow-up calls to customer contact centers. 9 Content will include: 10
a. An overview of the income verification process, and guidance on how to appeal 11 their assigned income bracket; 12
b. Visual examples of high, medium, and lower electricity bills before and after the 13 IGFC is implemented. Research findings indicate this must be explained through visuals that 14 customers can easily understand. These visuals will illustrate how rates were previously 15 structured, how the IGFC will adjust their bills based on various fixed charge amounts and 16 usage, and how the per-unit price of energy is lowered accordingly for all customers 17

3. Media Relations/IOU Blogs: The Joint IOUs anticipate the IGFC will receive 18 press attention, perhaps even before the CPUC makes its final decision. Customers and the 19 media may misconstrue the IGFC as a new charge or many focus on the fixed charge amount 20 itself, without the full context of the reduction in volumetric rates that results from showing 21 customers on a separate line item their costs for basic services that do not vary depending on 22 their usage. The Joint IOUs will engage and inform media about the construct of the proposed 23 IGFC, the legislative impetus behind it as a way to better support decarbonization, how all other 24 customer classes within California’s IOUs as well as other utilities and business entities employ 25 fixed charges, as well as how customers’ bills within each electric IOU’s service territory, may 26 be impacted for each of the four Income Brackets. Accurate local reporting about the IGFCs will 27 10/24/2023 D3 181 of 196

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be critical. Communication channels will include media engagement, social media and the Joint 1 IOUs’ blogs (Currents for PG&E, News Center for SDG&E, and Energized by Edison for SCE). 2

4. Digital Newsletters: The Joint IOUs propose to leverage their own digital 3 newsletters or similar email communications to feature information about the IGFC and link to 4 more information available online. 5

5. Paid Media: Using the successful individual default TOU paid media campaigns 6 as a case study for localized, paid outreach, the Joint IOUs plan to consider employing a 7 campaign to inform customers about the bill change. Paired with outreach through other 8 channels, cost-effective paid media can be used to target customers by geography, income (at the 9 ZIP code Level), in-language, and provide supplementary coverage to support other channels. 10 Before committing to customer funding for this effort, the Joint IOUs will explore customer 11 interest levels for this channel of messaging, and test ads to ensure they are simple, clear, 12 resonant, and that they add value beyond utility-owned communication channels. Paid media 13 channels may include highly targeted digital, search, and community and/or ethnic print 14 advertising. 15

6. Social Media: Social media channels (i.e., Twitter, Facebook, Instagram, 16 Nextdoor, and/or YouTube) may be leveraged as an interactive and targeted way to broadly 17 inform customers about the IGFC. Posts will be, brief, clear, and easy to understand, and will 18 guide customers to obtain more information online via direct links. 19

7. Collateral: Printed materials, such as brochures and fact sheets, may be produced 20 for use with various customer segments and through various channels, such as outreach teams, 21 field representatives, branch offices, and CBOs. 22
a. Quick-Response (QR) Codes: QR codes may be leveraged, where appropriate 23 and feasible, on print materials as another opportunity to connect customers directly to the Joint 24 IOUs’ websites, where they can find additional information and resources. 25

8. Integration: The Joint IOUs each will also identify opportunities to integrate 26 fixed charge messaging into other relevant ME&O efforts being otherwise undertaken by that 27 10/24/2023 D3 182 of 196

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IOU. Message integration will be based on how well the audience and calls to action overlap, 1 and which channel is used. In addition, different channels will be evaluated individually for their 2 potential to carry multiple messages. Messaging will also be integrated into planned outreach to 3 specific target groups such as low income, solar, and other program outreach. 4 J. Community Outreach Tactics 5

1. Community Based Outreach (CBO) 6
The Joint IOUs will collaborate with CBOs to help educate customers about what the 7 IGFC means for them and engage them in solutions including connecting them to valuable 8 programs, services, and tools. These organizations represent the diverse communities of PG&E, 9 SCE, and SDG&E service areas, spanning across agricultural, residential, civic, and public 10 sectors. Many of these CBOs are small grassroots agencies serving individuals with access and 11 functional needs, including those who are multicultural, multilingual, low-income, seniors, and 12 Limited English Proficient (LEP) audiences in communities of concern. 13 Together, the CBOs and the Joint IOUs will communicate why and when the IGFC is 14 being implemented, how customers may be impacted, the income verification processes, and 15 how they can appeal their assigned household income bracket. Additionally, low-income 16 customers who participate in CARE and FERA will be reassured that their program participation 17 benefits will not be impacted and shown how they may get greater assistance from the IGFC. 18 Efforts to inform customers about available resources for managing energy costs will 19 continue. CBOs regularly share communications about programs and services, such as Energy 20 Savings Assistance, Medical Baseline, and available rebates and incentives, through social 21 media, newsletters, eblasts, blog posts, and direct stakeholder engagement efforts like digital 22 webinars. 23
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2. Joint IOU Employee Outreach 1
ME&O activities will also include outreach and education to employees prior to the 2 implementation of the IGFC. Employees may be engaged through internal channels, including 3 internal events, emails, and internal online resources. Internal customer-facing groups will be 4 leveraged to help drive early education about the IGFC for utility-employees, especially those 5 whose work is customer-facing about the IGFC. Customer-facing groups may include the 6 employees at each of the Joint IOUs’ Customer Contact Centers, payment locations and branch 7 offices, field service teams, and credit and collections groups. 8

3. External Stakeholders: 9
Information will be provided to external stakeholders, including elected officials, tribal 10 leaders, local media, and Community Choice Aggregators, to help them understand the impetus 11 of the IGFC as well as its benefits, and to address potential questions from constituents. 12 K. Metrics and Tracking 13
The Joint IOUs propose to measure and track key pieces of outreach data to monitor 14 progress in reaching customers with messages about the IGFC. In more broad-based messaging 15 channels, this will include measurements including press article mentions, reach and/or 16 impressions of paid media, outbound targeted communications (like e-newsletters), bill 17 messages, email response, call center feedback, customer listening post, etc. Reporting on 18 account-level notifications and customer responses regarding IGFC assignments will also be 19 tracked. 20
L. Budget 21
In this section, the Joint IOUs identify ME&O-associated research and tactics that require 22 incremental revenue recovery to implement. Essential implementation costs include incremental 23 labor resources needed to develop, manage and implement the proposed ME&O tactics and the 24 10/24/2023 D3 184 of 196

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deliverables. The Joint IOUs are recommending a digital-first approach to mitigate costs. 1 However, not all customers have an email address on file and will require direct mail, which is 2 more costly. Additional prices that can drive up the ME&O budget include paid advertising. 3 Again, to mitigate costs and still effectively reach customers, the Joint IOUs are proposing more 4 targeted paid media strategies. The following are estimated ME&O costs, by IOU: 5 Table V-19
Initial Estimates of ME&O Costs, by IOU

These are still relatively high-level estimates based on what is currently understood about 6 implementation of the Joint IOUs’ Opening Testimony proposals; they may not reflect costs 7 associated with implementing whatever differing directives the CPUC may issue in its final 8 decision at the end of this proceeding, after all the evidence has been considered. The Joint 9 IOUs respectfully request the authority for each IOU (including the small IOUs) to file an 10 Advice Letter within 90-days after the Final Decision in which each IOU will provide its more 11 detailed final ME&O costs to implement what the final decision authorized, for which the Joint 12 IOUs propose be recovered through the balancing account approach described in the Cost 13 Recovery Chapter. 14
Chapters PG&E-01, SCE-02, and SDG&E-01, et seq., provide more detail on each of the 15 Joint IOUs’ respective utility-specific cost estimates related to these proposals. Differences 16 among the estimated costs provided by each of the Joint IOUs are primarily based on the 17 residential population size as well as the demographics within each IOU’s unique service 18 territory, as well as other IOU-specific considerations such as numbers of media markets and 19 costs of using such media markets’ channels.20
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VI. 1
COST RECOVERY 2
A. Introduction 3
This chapter discusses the cost recovery for the Joint IOUs’ proposal to establish an 4 income-graduated fixed charge for residential rates (IGFC) as discussed in other chapters of this 5 joint testimony and in the concurrently served IOU-specific testimony. This chapter discusses 6 the cost recovery and rate allocation (together “cost recovery”) for the Joint IOUs’ proposal to 7 establish an IGFC for residential rates, as discussed in other chapters of this joint testimony and 8 in the concurrently served IOU-specific testimony. The Joint IOUs provide preliminary cost 9 estimates in their separately submitted testimony sponsored by their respective witnesses. These 10 preliminary estimates are contingent on the Commission approving the IOUs’ proposals in the 11 Joint IOUs’ testimony and in the separately submitted testimony of each IOU. If the 12 Commission requires modifications to the Joint IOUs’ proposals, or approves different 13 proposals, the Joint IOUs’ estimates presented in their opening testimony would no longer be 14 applicable. As necessary, the Joint IOUs reserve the right to develop and submit updated cost 15 estimates based on the Commission’s final, adopted implementation approach. Specifically, 16 upon the issuance of a final Commission decision, the Joint IOUs expect that work for the 17 purpose of updating costs according to whatever was adopted will begin, and a process that can 18 allow cost recovery will be needed. After the Commission's final decision, as the IOUs, Energy 19 Division, and other interested third parties work through implementation, updates to these cost 20 estimates may be needed. Therefore, the Joint IOUs propose that the CPUC adopt cost recovery 21 mechanisms and processes that can accommodate the development of updated costs in the future. 22 Additionally, this chapter also discusses potential impacts to the cost recovery 23 mechanisms as a result of the new rate design associated with the IGFC and the corresponding 24 lower volumetric rate, shifting the recovery of certain categories of authorized costs from 25 volumetric rates to the fixed charge. The IOUs assert that the cost recovery authority for costs 26 10/24/2023 D3 186 of 196

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that are moved from a volumetric basis to the IGFC will not change. The IOUs anticipate that 1 there may be changes needed to their respective tariffs and preliminary statements as a result of 2 shifting the recovery of these costs from volumetric rates to the IGFC and propose to submit 3 separate advice letters with those modifications prior to the fixed charge going into effect. 4 Finally, this chapter proposes an IGFC Calibration Mechanism that would allow for 5 timely recovery of any large revenue imbalances (i.e., undercollections) as a result of 6 uncertainties around the accuracy of the income level forecasting, especially in the initial years 7 after implementation. A calibration mechanism will allow the Joint IOUs to adjust rates timely 8 to avoid large undercollections growing throughout a given year to an amount that would 9 significantly impact the following year’s rates. 10
The Joint IOUs propose the following cost recovery proposals for the Commission’s 11 consideration and approval: 12
 Authorize each Joint IOU to separately submit a Tier 2 advice letter after the approval 13 of the final decision to provide a budget consistent with the final decision and the 14 related revenue requirements; 15
 Authorize each Joint IOU to separately submit a Tier 1 advice letter, 30-days after the 16 issuance of a final decision in this proceeding, to establish a new two-way balancing 17 account to recover the costs associated with the final IGFC approach approved by the 18 CPUC at the end of this proceeding, to be recovered from all customers through 19 public purpose program (PPP) rates; 20
 Approve the Joint IOUs’ proposal that the Income Verification costs associated with 21 the IGFC be paid for through state funding rather than through ratepayers, which 22 would be accomplished by either having the IOU incur the Income Verification costs 23 as a debit in the IGFCBA with an offsetting credit for the amount of state funding 24 received or by having a Third-Party incur the costs with state funding provided 25 directly to the third party (in which case no debits or credits for Income Verification 26 would be included in the IGFCBA); 27
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 Approve the Joint IOUs’ proposal to separately submit a Tier 1 advice letter before 1 the IGFC goes into effect to modify any applicable tariffs and/or preliminary 2 statements, as needed, to maintain appropriate operation of cost recovery mechanisms 3 for cost items removed from volumetric rates and included in the IGFC; and 4  Approve the Joint IOUs’ proposal for an IGFC Calibration Mechanism to allow for 5 timelier recovery of any large revenue imbalances. 6
The Joint IOUs request the Commission approve their Joint Cost Recovery Proposal as 7 reasonable and necessary to implement each of their proposals to establish an IGFC for 8 residential rates, to promote the state’s electrification policy and adoption of technologies that 9 use electricity and reduce or avoid greenhouse gases (GHG). 10 B. Cost Recovery and Rate Making Proposal 11

1. Cost Recovery Advice Letters Filings 12
The costs separately presented by each of the Joint IOUs in its respective utility-specific 13 testimony are estimates based on what is known at present and are not meant to represent each 14 individual IOUs’ forecasted budget or the amount requested for recovery in rates. Upon issuance 15 of a final decision in this proceeding, the Joint IOUs propose to separately submit Tier 1 advice 16 letters within 30-days to each establish a new two-way balancing account, the Income Graduated 17 Fixed Charge Balancing Account (IGFCBA). The Joint IOUs propose that the effective date for 18 this new balancing account be the effective date of the decision in order to allow for an 19 immediate commencement of the work needed to implement the new IGFC. All costs recorded 20 to the IGFCBA would be incremental and would not include costs requested in the IOUs’ 21 General Rate Cases (GRCs) or other Commission-approved funding. 22 Additionally, the Joint IOUs propose that each IOU submit a separate Tier 2 advice letter 23 after the final decision is issued to provide a budget and the associated revenue requirements 24 based on the elements for the fixed charge adopted in the final decision. All actual costs incurred 25 by each IOU from the effective date of the final decision would be included in that IOU’s 26 10/24/2023 D3 188 of 196

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respective budget submitted in its Tier 2 advice letter. The revenue requirements included in 1 these Tier 2 advice letters, once approved, would become the authorized revenue requirements 2 used in the IGFCBA, as further discussed below. All costs recorded to the IGFCBA would be 3 incremental and would not include costs requested in the respective IOUs’ General Rate Cases 4 (GRCs) or other Commission approved funding. 5

2. Income Graduated Fixed Charge Balancing Account (IGFCBA) 6 As described in the Joint IOUs’ testimony and in the separately submitted testimony by 7 each IOU, the IOUs have identified three main cost categories associated with the IGFC: (1) 8 income verification,125 (2) implementation, and (3) marketing, education, and outreach (ME&O). 9 The Joint IOUs propose that all costs incurred by the IOU, i.e., the actual incremental operations 10 and maintenance (O&M) expenses and the capital-related revenue requirements associated with 11 the actual incremental capital expenditures, be tracked and recorded in a new balancing account, 12 the Income Graduated Fixed Charge Balancing Account (IGFCBA). 13 The IGFCBA will be a two-way balancing account that will track and record on an 14 annual basis the difference between (1) actual O&M expenses incurred plus the capital-related 15 revenue requirement associated with actual capital expenditures, and (2) the total authorized 16 revenue requirement. To the extent the actual capital-related revenue requirements and O&M 17 expenses are greater than or lesser than the authorized revenue requirement, the Joint IOUs 18 respectfully request authorization to recover or return, without further reasonableness review, the 19 difference (i.e., the December 31 balance) on an annual basis. The Joint IOUs propose to return 20 or recover the December 31 balance in their respective IGFCBAs from all customers through the 21 following year’s PPP rates126 using the annual year-end rate change advice letter process adopted 22

125 Income verification costs recorded to the IGFCBA and recovered from customers would be those costs not funded by the state of California‘s general fund as discussed below in Section B.4. of this chapter.
126 PG&E would transfer the December 31 balance in its IGFCBA to its Public Policy Charge Balancing Account (PPCBA). SCE would transfer the December 31 balance in its IGFCBA to its Public

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in Resolution E-5127. The annual authorized revenue requirements would be recovered on a 1 forecast basis in PPP rates.127 The Joint IOUs propose to no longer utilize the IGFCBAs once 2 the ongoing revenue requirements associated with maintenance and operations can be forecast 3 and included as part of GRC base rates.128 This timing will likely vary by IOU given the 4 difference in the timing of each of the Joint IOU’s GRC Phase 1 four-year cycle. 5 The Joint IOUs believe that two-way balancing account treatment is appropriate to 6 recover the cost categories outlined above because these costs are incremental amounts necessary 7 to comply with Assembly Bill 205. Additionally, two-way balancing account treatment is 8 appropriate in situations where the program or activity is highly volatile, difficult to estimate, 9 outside the utility’s control, and/or material to customers and investors. Two-way balancing 10 account treatment in these circumstances would ensure that neither customers nor investors are 11 disadvantaged unduly by inherently unpredictable program costs. As previously described above 12 and in the separately supplemental testimony concurrently provided by each of the Joint IOUs as 13 separate links within the same Notice of Availability used to serve this Joint IOU Opening 14 Testimony, there is a high degree of uncertainty in the ultimate cost of establishing an income-15 graduated fixed charge for residential rates. Two-way balancing account treatment provides a 16 reasonable method for addressing this uncertainty. A two-way balancing account requires the 17 Joint IOUs to return to their respective customers any revenue collected that exceed actual costs, 18 while allowing for unforeseen costs to be recovered.129 19

Purpose Programs Adjustment Mechanism (PPPAM). SDG&E would include the balance within its annual PPP advice letter.
127 PG&E would record its forecast authorized revenue requirement in its PPCBA. SCE would record its forecast authorized revenue requirement in its PPPAM. SDG&E would record its forecast authorized revenue requirement in its IGFCBA.
128 For PG&E, the ongoing recovery once in GRC base rates would be via the Distribution Revenue Adjustment Mechanism (DRAM). For SCE, the ongoing recovery once in GRC base rates would be via the Authorized Distribution Base Revenue Requirement (ADBRR). For SDG&E, the ongoing recovery once in GRC base rates would be via the Electric Distribution Fixed Costs Account (EDFCA).
129 If the utility does not have the ability to recover unforeseen costs, that can result in deferred or delayed work. To prevent this, the Commission has authorized two-way balancing accounts to ensure

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The Commission adopted a similar cost-recovery approach in the Gas Leak Abatement 1 proceeding (Rulemaking (R.) 15-01-008), when it authorized PG&E to create the two-way New 2 Environmental Regulations Balancing Account (NERBA)130 for incremental costs to implement 3 best practices to reduce methane emissions from gas systems. In doing so, the CPUC explained: 4 “The primary purpose of balancing accounts is to 5
ensure that a utility recovers its CPUC authorized revenue 6 requirement from ratepayers for a given program or functions, but 7 no more or less. [¶] Two-way balancing accounts authorize a utility 8 to collect more or less than the authorized revenue requirement for 9 an existing program depending on actual costs, and are intended to 10 ensure that the utility does not make or lose money to uncertainties 11 in the scope of work. [¶] The Commission typically reviews the 12 entries and the net balance in a balancing account and authorizes 13 recovery from or refunds to rate payers on an annual basis.”131 14 More recently in D.22-11-009, the Commission authorized PG&E to establish a two-way 15 balancing subaccount, the Third-Party DGEMS Contracts Subaccount, in the Microgrids 16 Balancing Account (MGBA)132 to record and recover costs related to Third-Party contracts for 17 multi-season Distributed Generation-Enabled Microgrid Services (DGEMS). Although the 18 Commission considered authorizing a one-way balancing account in which the amounts to be 19 spent and recovered from customers would be capped, it noted that “the costs incurred by PG&E 20 in any given year under a Third-Party Distributed Generation Enabled Microgrid Service 21 contract is likely to be different than the costs of it reasonably forecast at the time of the 22 proposing solution. Thus, the use of a one-way (capped) balancing account is suboptimal given 23 the variability.”133 As such, the Commission considered it “more reasonable”134 to authorize a 24 two-way balancing account while controlling costs through stakeholder review via the GRC or a 25 separate application. 26

that work is not deferred or delayed. See Section 8.1.1 of D.21-08-036, which directed SCE to establish a two-way Underground Structures Replacement Balancing Account (USRBA) given lack of clarity on the scope of the work and the desire for work not to be deferred. 130 See PG&E Gas Preliminary Statement Part DZ.
131 D.17-06-015, at p. 131.
132 See PG&E Electric Preliminary Statement Part IT.
133 D.22-11-009, at p. 47.
134 D.22-11-009, at p. 47.
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The Joint IOUs’ proposed approach to IGFC cost recovery, using a two-way balancing 1 account, allows the flexibility to “to ensure that the utility does not make or lose money due to 2 uncertainties in the scope of work.”135 Oversight would be achieved through the submittal of the 3 Tier 2 advice letters outlined above that would include a budget and revenue requirements based 4 on the adopted final decision. Therefore, it is reasonable and appropriate for the Commission to 5 authorize the establishment of two-way balancing accounts to recover the costs associated with 6 the IGFC for the reasons outlined above. 7

1. Recovery of the IGFCBA Via the PPP Rate Component 8
As discussed in the Policy and Rate Design Chapters above, the legislature intended 9 implementation of the IGFC to support California’s efforts against climate change and remove 10 the current disincentive to broad-scale customer adoption of beneficial electrification 11 technologies to reduce California’s GHG emissions. For these reasons, it is appropriate that the 12 costs needed to help support the movement to IGFCs are recovered from all customers because 13 all customers should experience the intended benefits of this change. The PPP charge funds 14 programs considered by law to benefit society. This includes costs to administer income 15 qualified programs such as the California Alternative Rates for Energy program (CARE) and 16 energy efficiency programs. Given the public purpose benefit associated with the integration of 17 IGFCs into residential rates, the related costs for this transition should be included in the PPP 18 rate, as the most appropriate rate component in which to recover costs associated with this shift. 19

2. Recovery of Income Verification Costs through State Funding 20 As discussed in the Policy Chapter, the Joint IOUs propose that the state of California’s 21 general fund be used as the primary funding source for costs related to income verification. As 22 discussed in the Income Verification Chapter of this Exhibit, recovery of all income verification 23 costs through rates could overly exacerbate the unaffordability of electric rates; thus, its inclusion 24 in rates could inappropriately disincentivize the beneficial electrification that caused the 25

135 D.17-06-015, at p. 131.
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legislature to pass AB 205. The Joint IOUs propose to collaborate with the CPUC to seek state 1 funding for these costs, lest the well-intended income verification for a first-ever progressive 2 fixed charge structure undermine the overall legislative intent. 3 If the costs associated with income verification are incurred by the IOU, but seeking state 4 funding for income verification is successful, the Joint IOUs propose that these costs be recorded 5 as debit entries in the IGFCBA with any offsetting state funding received recorded as credit 6 entries in the IGFCBA, which results in a net zero cost to ratepayers. If the IOUs do not incur 7 the costs associated with income verification (i.e., the costs are directly incurred by a Third-Party 8 and are not “charged back” to the IOU), no amounts (debits or credits) would need to be 9 recorded in the IGFCBA. Ultimately, if there are any income verification costs incurred by the 10 IOUs that are not offset with state funding, those costs would be recoverable from ratepayers via 11 the IGFCBA and the PPP rate as discussed in Sections B.2. and B.3 of this chapter. 12 C. Recovery of Authorized Costs via the IGFC 13
The new rate design associated with the IGFC, and lower volumetric rate will shift how 14 certain categories of authorized costs are recovered from a volumetric basis to a fixed charge. 15 The Commission will ultimately determine which costs will be included in IGFCs and moved out 16 of the volumetric rates. Shifting recovery from a volumetric basis to an IGFC basis should not 17 change the cost recovery authority for costs that are moved. For instance, GRC Phase 1 18 authorized distribution costs should still be entitled to rate recovery for differences between 19 forecast and actual sales or forecast and actual IGFC revenues. Other costs that are subject to 20 two-way balancing account recovery for the difference between authorized costs and actual costs 21 must continue to be recoverable on that basis, whether they are part of a fixed charge or 22 volumetric rate. 23
The Joint IOUs have not yet been able to determine what, if any of their respective tariffs 24 or preliminary statements, might need modification if costs authorized for recovery therein are 25 moved to a fixed charge, instead of volumetric rates. That evaluation will depend on what the 26 10/24/2023 D3 193 of 196

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Commission approves for inclusion in the fixed charge. Therefore, the Joint IOUs propose that, 1 after the CPUC’s final decision but before the fixed charge goes into effect, each IOU would 2 separately submit its own Tier 1 advice letter with proposed modifications to tariffs and/or 3 preliminary statements, if needed to maintain appropriate operation of cost recovery mechanisms 4 for cost items removed from volumetric rates and included in the fixed charge. 5 D. IGFC Calibration Mechanism 6
To enable ratesetting, the Joint IOUs will each need to forecast the number of residential 7 customer accounts that will fall into each IGFC income brackets. If there are deviations in what 8 the IOUs have forecasted compared to the income brackets that customers actually fall in when 9 billed, the potential exists for revenue imbalances that would have to be recovered in the 10 following year’s rates. It is most likely that this potential revenue imbalance would be an 11 undercollection, meaning that the forecasts overestimate the number of customers that would be 12 billed at the higher IGFC brackets because customers moving down in income level are more 13 likely to notify the utility given the potential economic hardship relative to customers who saw 14 increases in income. 15
Given the uncertainty around how accurate the income bracket assignment will be, 16 especially in the initial years after implementation, the Joint IOUs propose the authorization of 17 an IGFC Calibration Mechanism to allow for timelier recovery of any large revenue imbalance 18 undercollections as opposed to allowing the undercollections to grow throughout the year to an 19 amount that significantly impacts the following year’s rates. 20 The Joint IOUs’ proposed IGFC Calibration Mechanism would function as follows: 21  Beginning each year in January, and every month thereafter throughout the remainder 22 of the calendar year, an IOU will track the amount of revenue that was forecast to be 23 recovered via the IGFC (this can be done either at an aggregate level or at each 24 10/24/2023 D3 194 of 196

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income bracket with the IGFC) and the amount that was actually recovered via the 1 IGFC.136 2
 If the revenue imbalance results in an undercollection that exceeds 10 percent of the 3 forecast revenue to be recovered from the IGFC on a cumulative monthly basis,137 an 4 IGFC Calibration threshold will have been exceeded.138 5  Once an IGFC Calibration Mechanism has occurred, the IOU will have the option in 6 its next regularly scheduled rate change to do one of the following three activities: 7 o Option 1: Increase rates for the remainder of the calendar year139 to recover the 8 IGFC Calibration Mechanism Balance that exists as of one month preceding the 9 date of the rate change (i.e., a June 1 rate change would implement the under 10 collection that had accumulated from January through April, since May numbers 11 are not available until after June 1) AND adjust the IGFC income bracket 12 customer account forecast to mitigate the revenue imbalance from continuing to 13 accumulate on a going-forward basis; OR 14

136 This functionality will need to be built into the IOUs’ respective billing and revenue reporting systems, the costs of which would record to the IGFCBA. 137 For example, if the IGFC was set to recover $200 million in both January and February and only recovered $185 million and $180 million, respectively, the 10 percent IGFC Calibration Mechanism Threshold would not have been reached. However, in March, if the IGFC was set to recover $200 million and only recovered $170 million, the 10 percent IGFC Calibration Mechanism would have been reached because only $535 million of the $600 million forecasted would have been recovered (and that difference (i.e., the $65 million) exceeds 10 percent of $600 million (i.e., $60 million)). 138 There are no new cost recovery accounts needed to track the undercollection. Instead, the undercollection will record to the IOUs’ existing revenue balancing accounts based on which costs are ultimately included in the IGFC.
139 For example, if the IGFC Calibration Mechanism Balance was $300 million as of April 30 (and assuming all of the costs included in the IGFC are distribution-related costs solely for the purposes of this example), the IOU would increase its June 1 distribution-related revenue requirement by $300 million for the remainder of the calendar year to be recovered from all customers. Whatever balance remained at the end of the calendar year would be included in the annual year-end ratesetting true-up process as directed in Resolution E-5217. Assuming perfect ratemaking and all else being equal, this would result in an undercollection of only $125 million at year-end instead of $300 million (and significantly more given the undercollection would likely have continued into the remaining months of the year).
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o Option 2: Only adjust the IGFC income bracket customer account forecast to 1 mitigate the revenue imbalance from continuing to accumulate on a going-2 forward basis (but do not change rates to recover the existing IGFC Calibration 3 Mechanism Balance);140 OR 4
o Option 3: Take no action. 5
 The Joint IOUs would use their Tier 1 or Tier 2 rate change advice letters (based on 6 the tier level presently used) to effectuate the IGFC Calibration Mechanism process, 7 including the rationale for selecting Option 1, 2 or 3. 8  The Joint IOUs propose to have the IGFC Calibration Mechanism take effect in the 9 second year following the implementation of the IGFC to minimize rate volatility in 10 the first year of implementation (recognizing this could result in sizeable 11 undercollections that would be recovered in the second year after implementation). 12 Ideally, the IGFC Calibration Mechanism will ultimately prove to be unnecessary. 13 However, the Joint IOUs respectfully request that the Commission authorize the establishment of 14 this mechanism to protect against the potential for sizeable undercollections that would result in 15 upward pressure on rates for customers in the following year and cash flow and financing 16 impacts to the utility in the current year. 17

140 This option would most likely be utilized in situations where an undercollection resulted from deviations to the IGFC income level forecast, but the revenue balancing account overall was overcollected or barely undercollected. This could occur, for example, during periods where an IOU overcollects on the volumetric portion of the rate due to weather-related events like heat waves. 10/24/2023 D3 196 of 196

Vista City CouncilOctober 24, 2023

Vista City Council
October 24, 2023