Agenda packet — Silicon Valley Clean Energy Executive Committee, April 28, 2023

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Pursuant to the Americans with Disabilities Act, if you need special assistance in this meeting, please contact the Clerk for the Authority at (408) 721-5301 x1005. Notification 48 hours prior to the meeting will enable the Authority to make reasonable arrangements to ensure accessibility to this meeting. (28 CFR 35.105 ADA Title II).

Aptos, CA 95003
Morgan Hill City Hall
17575 Peak Ave.

Morgan Hill, CA 95037
Teleconference Meeting Information:
https://svcleanenergy-org.zoom.us/j/85717967853
Telephone (Audio only):

US: +1 669 219 2599
Webinar ID: 857 1796 7853
Members of the public may observe this meeting electronically by accessing the meeting via instructions above. Public Comments can be sent in advance of the meeting via email up to three hours before the meeting begins to Board Clerk Andrea Pizano at [email protected] and will be distributed to the Executive Committee. The public will also have an opportunity to provide comments during the meeting. Members of the public using Zoom may comment during public comment or the applicable agenda item by using the Raise Hand feature and you will be recognized by the Chair. Those using the telephone (audio only) feature should press star 9 on your phones to initiate the “Raise Hand” function in Zoom. You will then be announced, unmuted, and your time to speak will begin.

The public may provide comments on any matter listed on the Agenda. Speakers are customarily limited to 3 minutes each, however, the Committee Chair may increase or decrease the time allotted to each speaker based on the number of speakers, the length of the agenda and the complexity of the subject matter. Speaking time will not be decreased to less than one minute.

If you are an individual with a disability and need a reasonable modification or accommodation pursuant to the Americans with Disabilities Act (“ADA”) please contact Board Clerk Andrea Pizano at [email protected] prior to the meeting for assistance.

AGENDA
Call to Order

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George Tyson, Chair
Town of Los Altos Hills
Tina Walia, Vice Chair
City of Saratoga
Elliot Scozzola
City of Campbell
Sheila Mohan
City of Cupertino
Zach Hilton
City of Gilroy
Sally Meadows
City of Los Altos
Rob Rennie
Town of Los Gatos
Evelyn Chua
City of Milpitas
Bryan Mekechuk
City of Monte Sereno
Yvonne Martinez Beltran
City of Morgan Hill
Margaret Abe-Koga
City of Mountain View
Larry Klein
City of Sunnyvale
Otto Lee
County of Santa Clara
svcleanenergy.org
333 W El Camino Real
Suite 330
Sunnyvale, CA 94087
Roll Call
Public Comment on Matters Not Listed on the Agenda
The public may provide comments on any matter not listed on the Agenda provided that it is within the subject matter jurisdiction of SVCE. Speakers are customarily limited to 3 minutes each, however, the Committee Chair may increase or decrease the time allotted to each speaker based on the number of speakers, the length of the agenda and the complexity of the subject matter. Speaking time will not be decreased to less than one minute.

Consent Calendar (Action)
1) Approve Minutes of the March 24, 2023, Executive Committee Meeting Regular Calendar
2) CEO Update (Discussion)
3) Update on Budget Trailer Bill and AB 1373 (Discussion) 4) Recommendation to Authorize a Request for Extension to Comply with Load Management Standards (Action)
5) Enterprise Risk Management Framework (Discussion)
6) Results of Stress Test Analyses for FY2024- FY2028 Planning Horizon (Discussion)
7) Programs Snapshot: Expanding Charging Incentives to New Affordable Housing (Presentation – Information Only)
Committee/Staff Remarks
Adjourn
Silicon Valley Clean Energy
Executive Committee Meeting
Friday, March 24, 2023
10:00 a.m.

Silicon Valley Clean Energy Office
333 W El Camino Real, Suite 330
Sunnyvale, CA

DRAFT MEETING MINUTES
Call to Order
Chair Walia called the meeting to order at 10:01 a.m.

Roll Call

Present:

Chair Tina Walia, City of Saratoga
Vice Chair Bryan Mekechuk, City of Monte Sereno
Director George Tyson, Town of Los Altos Hills
Director Yvonne Martinez Beltran, City of Morgan Hill (arrived at 10:29 a.m.)

Absent:

Director Rob Rennie, Town of Los Gatos
Public Comment on Matters Not Listed on the Agenda
No speakers.

Consent Calendar
MOTION: Vice Chair Mekechuk moved and Director Tyson seconded the motion to approve the Consent Calendar.

Chair Walia opened public comment.

No speakers.

Chair Walia closed public comment.

The motion carried by verbal roll call vote with Directors Martinez Beltran and Rennie absent. 1) Approve Minutes of the February 24, 2023, Executive Committee Meeting Regular Calendar
2) CEO Update (Discussion)
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Item 1 1 Draft Minutes: 3/24/23 Executive Committee Meeting CEO Girish Balachandran welcomed attendees to the first in-person meeting of the Executive Committee at suite 330 in the SVCE office. CEO Balachandran spoke to the following items:
• The Governor’s budget change proposals surrounding central procurement, penalty structure, and the CPUC’s authority to order load serving entities’ procurement; and • The Bay Area Air Quality Management District’s action to pass rules associated with banning appliances that emit nitrous oxides.

CEO Balachandran responded to committee member questions.

Chair Walia opened public comment.

No speakers.

Chair Walia closed public comment.
3) Recommend Board Approval of Operating Rules and Regulations Amendment to Expand Executive Committee Membership to Up to Six Board Members (Action) Board Clerk Andrea Pizano provided a presentation requesting the Executive Committee recommend that the Board of Directors approve the proposed amendment to SVCE’s Operating Rules and Regulations to expand Executive Committee membership to up to six Board members. Board Clerk Pizano noted if approved, the item would be included on the April Board of Directors meeting agenda and the May Board of Directors meeting agenda for final approval. An item would also be brought to the Board of Directors in May to appoint a sixth member to the existing Executive Committee.

Chair Walia opened public comment.

No speakers.

Chair Walia closed public comment.

MOTION: Vice Chair Mekechuk moved and Director Tyson seconded the motion to recommend the Board of Directors approve the proposed amendment to SVCE’s Operating Rules and Regulations to expand Executive Committee membership to up to six Board members.

The motion carried with Directors Martinez Beltran and Rennie absent. 4) Recommend the SVCE Board of Directors Authorize the Chief Executive Officer to Negotiate and Execute a Power Purchase Agreement with Middle River Power for up to 100 MW of a Natural Gas Peaker Plant combined with up to 134 MWs of Battery Energy Storage System for a term of 12 years to meet Resource Adequacy and Mid-term Reliability Procurement Order Requirements (Action) Director Martinez Beltran arrived during Item 4.

Monica Padilla, COO and Director of Power Resources, and Charles Grinstead, Senior Manager of Power Resources, provided a presentation requesting the committee recommend the SVCE Board authorize the CEO to negotiate and execute a power purchase agreement with Middle River Power. The presentation addressed California’s clean goals, reliability challenges and requirements; SVCE’s energy and capacity portfolio, procurement and progress efforts; Middle River Power’s Hanford hybrid natural gas power plant with battery energy storage system; and the staff recommendation.

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Item 1 2 Draft Minutes: 3/24/23 Executive Committee Meeting Staff responded to Executive Committee member questions regarding the project, what could be done with the funds that would be set aside to mitigate emissions associated with the energy produced from the project, other CCAs engaging in similar projects, and information on natural gas.

Chair Walia opened public comment.

No speakers.

Chair Walia closed public comment.

MOTION: Director Tyson moved and Director Martinez Beltran seconded the motion to recommend the SVCE Board of Directors:

1. Delegate Authority to CEO to finalize and execute a Power Purchase Agreement with Middle River Power for its Hybrid Natural Gas Power Plant with Battery Energy Storage System, with the following parameters:
• 99.4 MW of Resource Adequacy Capacity from Natural Gas Power Plant • New 131.4 MW, one-hour BESS at site for an additional 16 MW of Resource Adequacy and Mid-term Reliability Procurement Order compliant capacity • Option to utilize toll energy under certain conditions to meet reliability • 12-year term with an expected on-line date of April 2024 • Not to exceed dollar amount: $280,000,000

2. Approve exception to the Energy Risk Management Policy to enable gas transactions needed to manage Hanford PPA

3. Direct staff to develop a policy and/or guidelines to set aside funds to be used for programs and/or projects to mitigate emissions associated with energy produced by the Hanford project resulting from the Hanford PPA
The motion carried with Director Rennie absent.
5) Recommend the SVCE Board of Directors Authorize the Chief Executive Officer to Negotiate and Execute a Power Purchase Agreement with Rio Bravo Fresno for up to 25 Megawatts of Biomass Renewable Energy for 2.75 years to meet Renewable Portfolio Standard and Resource Adequacy Requirements (Action)
Senior Manager of Power Resources Grinstead presented a PowerPoint presentation requesting the Executive Committee recommend the SVCE Board of Directors authorize the CEO to negotiate and execute a power purchase agreement with Rio Bravo Fresno for up to 25 megawatts of biomass renewable energy. The presentation included the request and justification, background on the project, and next steps.

Staff responded to committee member questions about the project.

Chair Walia opened public comment.

No speakers.

Chair Walia closed public comment.

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Item 1 3 Draft Minutes: 3/24/23 Executive Committee Meeting MOTION: Director Martinez Beltran moved and Vice Chair Mekechuk seconded the motion to recommend the SVCE Board of Directors delegate authority to the CEO to execute a short-term power purchase agreement (PPA) with Rio Bravo Fresno Biomass energy, with the following parameters:
• Capacity: 25 megawatts
• Est. Annual Generation: 175,000 MWhs
• Price: fixed dollar per megawatt hour
• Term: 2.75 years, May 1, 2023, through December 31, 2025 • Not-to-exceed dollar amount: $60,000,000
The motion carried with Director Rennie absent.
6) Electrification Discount Design Update (Discussion)
Peter Mustacich, Energy Services Lead, provided a presentation to the Executive Committee with a request for feedback on the staff recommendation to adopt the “TOU Super” discount design.

Energy Services Lead Mustacich responded to committee member questions regarding the energy usage profiles and discount designs presented, and shared their feedback on the questions posed by staff which included:

1. Would you support the staff recommendation to adopt the “TOU Super” discount design?

2. Would you support the decision not to include bill-protection?

3. Should we guarantee the discount until 2027 to align with BAAQMD’s zero-NOx appliance rulemaking? Chair Walia opened public comment.

Bruce Karney commented on the proposed rate structure, noting there were two things that the structure could incentivize: 1) for people who have a qualifying technology already, to modify the timing of the charging they do of their car, and 2) incentivize people who do not have a qualifying technology to make a purchasing decision to go out and get it. Karney noted his concern if there is a limitation on the number of customers that can be accommodated in this program, to make sure the program is designed to incentivize people doing new things that they wouldn’t have done already.

Chair Walia closed public comment.

The committee discussed evaluating a monitored phased enrollment for a limited time, and staff noted other program proposals incorporating the committee’s comments would be brought back to the group. 7) Programs Snapshot: Member Agency Programs and Workgroup Activities (Presentation – Information Only)
Senior Manager of Public Sector Services, Tony Eulo, presented information on member agency programs including the Community Energy Resilience and Electrification Demonstration grants, modernizing program processes, policy experimentation, reach code support, technical assistance for EV fleet planning, the member agency working group, SVTEC, and expansion of assistance with grant applications.

Chair Walia opened public comment.

No speakers.

Chair Walia closed public comment.

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Item 1 4 Draft Minutes: 3/24/23 Executive Committee Meeting Committee/Staff Remarks
CEO Balachandran noted there is a Cities Association meeting in June, and staff is looking to contribute to that meeting.

Director Martinez Beltran announced Cal Cities would be having a legislative summit in Sacramento April 12-14, 2023.

Adjournment
Chair Walia adjourned the meeting at 12:09 p.m.

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Item 1 5 Draft Minutes: 3/24/23 Executive Committee Meeting

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Staff Report – Item 2
Item 2: CEO Update
From: Girish Balachandran, CEO
Prepared by: Andrea Pizano, Board Clerk/Executive Assistant Date: 4/28/2023
This item will be addressed in the form of an oral report to the Executive Committee.

Item 2
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Staff Report – Item 3
Item 3: Update on Budget Trailer Bill and AB 1373
From: Girish Balachandran, CEO
Prepared by: Bena Chang, Senior Government Affairs Manager Date: 4/28/2023

BACKGROUND
Earlier this year, Governor Newsom released an Energy Budget Trailer bill that contained policy proposals that intend to increase energy reliability. Recently, Assemblymember Eduardo Garcia introduced AB 1373, which contains the Governor’s key policy proposals in a legislative vehicle.

While there are slight differences between the Budget Trailer Bill and AB 1373, both contain 3 major provisions:
1) Central Procurement: The proposals would allow the California Public Utilities Commission (CPUC) to direct Investor-Owned Utilities (IOUs) or the State Department of Water Resources (DWR) to centrally procure diverse clean energy resources. The CPUC would have the ability to define what resources qualify as “diverse clean energy.”
2) CPUC Authority Expansion: The proposals include language to broadly expand the CPUC’s authority to order CCA procurement under the Integrated Resource Plan. 3) Capacity Payments: The proposals set up a new additional capacity payment for Load Serving Entities (LSEs) that do not meet their capacity obligations when the state’s Strategic Reliability Reserve is activated. These capacity payments would be on top of any penalties assessed by the CPUC for Resource Adequacy deficiencies and any payments LSEs make to the California Independent System Operator (CAISO) for backstop procurement.

ANALYSIS & DISCUSSION
SVCE staff will provide an update on the Budget Trailer Bill and AB 1373 to the Executive Committee on April 28, 2023.

ATTACHMENTS

1. Governor’s Budget Trailer Bill

2. AB 1373 (Garcia) Bill Text

3. CalCCA’s Oppose Unless Amended Letter on AB 1373 (Garcia) Item 3
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An act to amend Section 10295.6 of the Public Contract Code, to amend Section 25792 of the Public Resources Code, to amend Sections 365.1, 380, 454.51, 454.52, 454.53, 712, 712.1, and 712.8 of, and to add Section 913.12 to, the Public Utilities Code, and to amend Sections 80710 and 80720 of, to add Sections 80713 and 80714 to, to add Chapter 5 (commencing with Section 80740) to Division 29 of, and to add Division

29.5 (commencing with Section 80800) to, the Water Code, relating to energy, and making an appropriation therefor, to take effect immediately, bill related to the budget.

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THE PEOPLE OF THE STATE OF CALIFORNIA DO ENACT AS FOLLOWS:

SECTION 1. Section 10295.6 of the Public Contract Code is amended to read:
10295.6. Sections 10295 and 10297 do not apply to any contract entered into by the Department of Water Resources under Part 3 (commencing with Section 11100) of Division 6 or 6, Chapter 8 (commencing with Section 12930) of Part 6 of Division 6 6, Division 29 (commencing with Section 80700), or Division 29.5 (commencing with Section 80800), of the Water Code for the acquisition, sale, or transmission of power, or for services to facilitate those activities.

SEC. 2. Section 25792 of the Public Resources Code is amended to read:
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 may include all energy customers in the state, except those enrolled in demand response or emergency load reduction programs offered by entities under the jurisdiction of the Public Utilities Commission. The commission, in consultation with the Public Utilities Commission, may adopt additional participation requirements or limitations. 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)
(c) 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)
(d) 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 useful life of the resources in relation to the state’s climate and air quality requirements. (f)
(e) 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.

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(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.

SEC. 3. Section 365.1 of the Public Utilities Code is amended to read:
365.1. (a) Except as expressly authorized by this section, and subject to the limitations in subdivisions (b) and (c), the right of retail end-use customers pursuant to this chapter to acquire service from other providers is suspended until the Legislature, by statute, lifts the suspension or otherwise authorizes direct transactions. For purposes of this section, “other provider” means any person, corporation, or other entity that is authorized to provide electric service within the service territory of an electrical corporation pursuant to this chapter, and includes an aggregator, broker, or marketer, as defined in Section 331, and an electric service provider, as defined in Section 218.3. “Other provider” does not include a community choice aggregator, as defined in Section 331.1, and the limitations in this section do not apply to the sale of electricity by “other providers” to a community choice aggregator for resale to community choice aggregation electricity consumers pursuant to Section 366.2. (b) The commission shall allow authorize individual retail nonresidential end-use customers to acquire electric service from other providers in each electrical corporation’s distribution service territory, up to a maximum allowable total kilowatthours annual limit. The maximum allowable annual limit shall be established by the commission for each electrical corporation at the maximum total kilowatthours supplied by all other providers to distribution customers of that electrical corporation during any sequential 12-month period between April 1, 1998, and the effective date of this section. October 11, 2009. Within six months of the effective date of this section, or by July 1, 2010, whichever is sooner, October 11, 2009, the commission shall adopt and implement a reopening schedule that commences immediately and will phase in the allowable amount of increased kilowatthours over a period of not less than three years, and not more than five years, raising the allowable limit of kilowatthours supplied by other providers in each electrical corporation’s distribution service territory from the number of kilowatthours provided by other providers as of the effective date of this section, October 11, 2009, to the maximum allowable annual limit for that electrical corporation’s distribution service territory. The commission shall review and, if appropriate, modify its currently effective rules governing direct transactions, but that review shall not delay the start of the phase-in schedule. (c) Once the commission has authorized additional direct transactions pursuant to subdivision (b), it shall do both of the following:
(1) Ensure that other providers are subject to the same requirements that are applicable apply to the state’s three largest electrical corporations under any programs or rules adopted by the commission to implement the resource adequacy provisions of Section 380, the renewables portfolio standard provisions of Article 16 (commencing with Section 399.11), and the requirements for the electricity sector adopted by the State Air Resources Board pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code). Code), and the requirements of the integrated resource planning process as specified in Sections 454.5 to 454.6, inclusive. This requirement applies notwithstanding any prior decision of the commission to the contrary.

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(2) (A) Ensure that, in the event that the commission authorizes, in the situation of a contract with a third party, or orders, in the situation of utility-owned generation, an electrical corporation to obtain generation resources that the commission determines are needed to meet system or local area reliability needs for the benefit of all customers in the electrical corporation’s distribution service territory, the net capacity costs of those generation resources are allocated on a fully nonbypassable basis consistent with departing load provisions as determined by the commission, to all of the following:
(i) Bundled service customers of the electrical corporation. (ii) Customers that purchase electricity through a direct transaction with other providers.
(iii) Customers of community choice aggregators.
(B) If the commission authorizes or orders an electrical corporation to obtain generation resources pursuant to subparagraph (A), the commission shall ensure that those resources meet a system or local reliability need in a manner that benefits all customers of the electrical corporation. The commission shall allocate the costs of those generation resources to ratepayers in a manner that is fair and equitable to all customers, whether they receive electric service from the electrical corporation, a community choice aggregator, or an electric service provider. (C) The resource adequacy benefits of generation resources acquired by an electrical corporation pursuant to subparagraph (A) shall be allocated to all customers who pay their net capacity costs. Net capacity costs shall be determined by subtracting the energy and ancillary services value of the resource from the total costs paid by the electrical corporation pursuant to a contract with a third party or the annual revenue requirement for the resource if the electrical corporation directly owns the resource.

An energy auction shall not be required as a condition for applying this allocation, but may be allowed as a means to establish the energy and ancillary services value of the resource for purposes of determining the net costs of capacity to be recovered from customers pursuant to this paragraph, and the allocation of the net capacity costs of contracts with third parties shall be allowed for the terms of those contracts. (D) It is the intent of the Legislature, in enacting this paragraph, to provide additional guidance to the commission with respect to the implementation of subdivision (g) of Section 380, as well as and to ensure that the customers to whom the net costs and benefits of capacity are allocated are not required to pay for the cost of electricity they do not consume.
(d) (1) If the commission approves a centralized resource adequacy mechanism pursuant to subdivisions (h) and (i) of Section 380, upon the implementation of the centralized resource adequacy mechanism the requirements of paragraph (2) of subdivision (c) shall be suspended. If the commission later orders that electrical corporations cease procuring capacity through a centralized resource adequacy mechanism, the requirements of paragraph (2) of subdivision (c) shall again apply. (2) If the use of a centralized resource adequacy mechanism is authorized by the commission and has been implemented as set forth in paragraph (1), the net capacity costs of generation resources that the commission determines are required to meet urgent system or urgent local grid reliability needs, and that the commission authorizes to be procured outside of the Section 380 or Section 454.5 processes, shall be recovered according to the provisions of paragraph (2) of subdivision (c).

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(3) This subdivision does not supplant the resource adequacy requirements of Section 380 or the resource procurement procedures established in Section 454.5. (e) On or before June 1, 2019, the commission shall issue an order regarding direct transactions that provides as follows:
(1) Increase the maximum allowable total kilowatthours annual limit by 4,000 gigawatthours and apportion that increase among the service territories of the electrical corporations.
(2) All residential and nonresidential customer accounts that are on direct access as of January 1, 2019, remain authorized to participate in direct transactions. (f) (1) On or before June 1, 2020, the commission shall provide recommendations to the Legislature on implementing a further direct transactions reopening schedule, including, but not limited to, the phase-in period over which the further direct transactions shall occur for all remaining nonresidential customer accounts in each electrical corporation’s service territory.
(2) In developing the recommendations pursuant to paragraph (1), the commission shall find all of the following:
(A) The recommendations are consistent with the state’s greenhouse gas emission reduction goals.
(B) The recommendations do not increase emissions of criteria air pollutants and toxic air contaminants.
(C) The recommendations ensure electrical system reliability. (D) The recommendations do not cause undue shifting of costs to bundled service customers of an electrical corporation or to direct transaction customers. (3) (A) The recommendations shall be provided in compliance with Section 9795 of the Government Code.
(B) Pursuant to Section 10231.5 of the Government Code, this subdivision is inoperative on June 1, 2024.

SEC. 4. Section 380 of the Public Utilities Code is amended to read:
380. (a) The commission, in consultation with the Independent System Operator, shall establish resource adequacy requirements for all load-serving entities. (b) In establishing resource adequacy requirements, the commission shall ensure the reliability of electrical service in California while advancing, to the extent possible, the state’s goals for clean energy, reducing air pollution, and reducing emissions of greenhouse gases. The resource adequacy program shall achieve all of the following objectives:
(1) Facilitate development of new generating, nongenerating, and hybrid capacity and retention of existing generating, nongenerating, and hybrid capacity that is economic economical and needed. needed for reliability and to achieve the state policy specified in Section 454.53.
(2) Establish new, or maintain existing, demand response products and tariffs that facilitate the economic economical dispatch and use of demand response that can either meet or reduce an electrical corporation’s resource adequacy requirements, as determined by the commission.
(3) Equitably allocate the cost of generating capacity and demand response in a manner that prevents the shifting of costs between customer classes. (4) Minimize enforcement requirements and costs.

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(5) Maximize the ability of community choice aggregators to determine the generation resources used to serve their customers.
(c) Each load-serving entity shall maintain physical generating capacity and electrical demand response adequate to meet its load requirements, including, but not limited to, peak demand and planning and operating reserves. The generating capacity or electrical demand response shall be deliverable to locations and at times as may be necessary to maintain electrical service system reliability, local area reliability, and flexibility.
(d) Each load-serving entity shall, at a minimum, meet the most recent minimum planning reserve and reliability criteria approved by the board of directors of the Western Systems Coordinating Council or the Western Electricity Coordinating Council. (e) The commission shall implement and enforce the resource adequacy requirements established in accordance with this section in a nondiscriminatory manner.

Each load-serving entity shall be subject to the same requirements for resource adequacy and adequacy, the renewables portfolio standard program program, and the integrated resource planning process pursuant to Section 454.52 that are applicable apply to electrical corporations pursuant to this section, or otherwise required by law, or by order or decision of the commission. The commission shall exercise its enforcement powers to ensure compliance by all load-serving entities. (f) (1) The commission shall require sufficient information, including, but not limited to, anticipated load, actual load, and measures undertaken by a load-serving entity to ensure resource adequacy, to be reported to enable the commission to determine compliance with the resource adequacy requirements established by the commission. (2) The commission shall calculate and publish annually on its internet website, in a new report or as part of another report, the percentage of each load-serving entity’s local and system resource adequacy requirements from the previous calendar year that was met with capacity from eligible renewable energy resources pursuant to the California Renewables Portfolio Standard Program (Article 16 (commencing with Section 399.11)), other zero-carbon resources, including large hydroelectric and nuclear resources, or energy storage resources. In determining the percentage of each load-serving entity’s resource adequacy requirements, the commission shall include all directly owned or contracted resources and each load-serving entity’s allocation of any centrally procured resources or allocation of resources pursuant to any other mechanism that involves an assignment or allocation of resources purchased or owned by a single buyer, and shall exclude any share of a load-serving entity’s resources that were allocated to another load-serving entity.
(g) An electrical corporation’s costs of meeting or reducing resource adequacy requirements, including, but not limited to, the costs associated with system reliability, local area reliability, and flexibility, flexible resource adequacy, renewable integration, or resource diversity portfolio requirements, that are determined to be reasonable by the commission, or are otherwise recoverable under a procurement plan approved by the commission pursuant to Section 454.5, shall be fully recoverable from those customers on whose behalf the costs are incurred, as determined by the commission, at the time the commitment to incur the cost is made, on a fully nonbypassable basis, as determined by the commission. The commission shall exclude any amounts authorized to be recovered pursuant to Section 366.2 when authorizing the amount of costs to be recovered from customers of a community choice aggregator or from UNBACKED 02/08/23 09:11 AM
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customers that purchase electricity through a direct transaction pursuant to this subdivision.
(h) The commission shall determine and authorize the most efficient and equitable means for achieving all of the following:
(1) Meeting the objectives of this section.
(2) Ensuring that investment is made in new generating capacity. capacity, including the capacity needed to achieve the state policy specified in Section 454.53. (3) Ensuring that existing generating capacity that is economic is retained. retained, including the capacity needed to maintain reliability while achieving the state policy specified in Section 454.53.
(4) Ensuring that the cost of generating capacity and demand response is allocated equitably.
(5) Ensuring that community choice aggregators can determine the generation resources used to serve their customers.
(6) Ensuring that investments are made in new and existing demand response resources that are cost effective and help to achieve electrical grid reliability and the state’s goals for reducing emissions of greenhouse gases. (7) Minimizing the need for backstop procurement by the Independent System Operator.
(i) In making the determination pursuant to subdivision (h), the commission may consider a centralized resource adequacy mechanism among other options. (j) The commission shall ensure appropriate valuation of both supply and load modifying demand response resources. The commission, in an existing or new proceeding, shall establish a mechanism to value load modifying demand response resources, including, but not limited to, the ability of demand response resources to help meet distribution needs and transmission system needs and to help reduce a load-serving entity’s resource adequacy obligation pursuant to this section. In determining this value, the commission shall consider how these resources further the state’s electrical grid reliability and the state’s goals for reducing emissions of greenhouse gases. The commission, Energy Commission, and Independent System Operator shall jointly ensure that changes in demand caused by load modifying demand response are expeditiously and comprehensively reflected in the Energy Commission’s Integrated Energy Policy Report forecast, forecast and in planning proceedings and associated analyses, and shall encourage reflection of these changes in demand in the operation of the grid.
(k) For purposes of this section, “load-serving entity” means an electrical corporation, electric service provider, or community choice aggregator. “Load-serving entity” does not include any of the following:
(1) A local publicly owned electric utility.
(2) The State Water Resources Development System commonly known as the State Water Project.
(3) Customer generation located on the customer’s site or providing electric service through arrangements authorized by Section 218, if the customer generation, or the load it serves, meets one of the following criteria:
(A) It takes standby service from the electrical corporation on a commission-approved rate schedule that provides for adequate backup planning and operating reserves for the standby customer class.

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(B) It is not physically interconnected to the electrical transmission or distribution grid, so that, if the customer generation fails, backup electricity is not supplied from the electrical grid.
(C) There is physical assurance that the load served by the customer generation will be curtailed concurrently and commensurately with an outage of the customer generation.

SEC. 5. Section 454.51 of the Public Utilities Code is amended to read:
454.51. The commission shall do all of the following:
(a) Identify a diverse and balanced portfolio of resources needed to ensure a reliable electricity supply that provides optimal integration of renewable energy and resource diversity in a cost-effective manner. The portfolio shall be used by the commission to establish integrated resource planning-based procurement requirements that rely upon on zero carbon-emitting resources to the maximum extent reasonable and be designed to achieve the state policy specified in Section 454.53 and any statewide greenhouse gas emissions limit established pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code) or any successor legislation.
(b) Direct each electrical corporation to include, as part of its proposed procurement plan, a strategy for procuring best-fit and least-cost resources to satisfy the portfolio needs identified by the commission pursuant to subdivision (a). (c) Ensure that the net costs of any incremental renewable energy integration or diversification resources procured by an electrical corporation corporation, or the Department of Water Resources, to satisfy the need identified in subdivision (a) are allocated on a fully nonbypassable basis consistent with the treatment of costs identified in paragraph (2) of subdivision (c) of Section 365.1.
(d) Permit community choice aggregators to submit proposals for satisfying their portion of the renewable integration need identified in subdivision (a). If the commission finds this need is best met through long-term procurement commitments for resources, community choice aggregators shall also be required to make long-term commitments for resources. The commission shall approve proposals pursuant to this subdivision if it finds all of the following:
(1) The resources proposed by a community choice aggregator will provide equivalent integration of renewable energy.
(2) The resources proposed by a community choice aggregator will promote the efficient achievement of state energy policy objectives, including reductions in greenhouse gas emissions.
(3) Bundled customers of an electrical corporation will be indifferent from the approval of the community choice aggregator proposals.
(e) Ensure that all costs resulting from nonperformance to satisfy the need identified in subdivision (a) or (d), as applicable, shall be borne by the electrical corporation or community choice aggregator load-serving entity, as defined in Section 380, that failed to perform.

SEC. 6. Section 454.52 of the Public Utilities Code is amended to read:
454.52. (a) (1) Beginning in 2017, and to be updated regularly thereafter, the commission shall adopt a process for each load-serving entity, as defined in Section 380, to file an integrated resource plan, and a schedule for periodic updates to the plan, and shall ensure that load-serving entities do all of the following:

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(A) Meet the greenhouse gas emissions reduction targets established by the State Air Resources Board, in coordination with the commission and the Energy Commission, for the electricity sector and each load-serving entity that reflect the electricity sector’s percentage in achieving the economywide greenhouse gas emissions reductions pursuant to Section 38566 of the Health and Safety Code.
(B) Procure at least 60 percent eligible renewable energy resources by December 31, 2030, consistent with the state policy specified in Section 454.53 and Article 16 (commencing with Section 399.11) of Chapter 2.3.
(C) Enable each electrical corporation to fulfill its obligation to serve its customers at just and reasonable rates.
(D) Minimize impacts on ratepayers’ bills.
(E) Ensure system and local reliability on both a near-term and long-term basis, including meeting the near-term and forecast long-term resource adequacy requirements of Section 380, and require sufficient, predictable resource procurement and development to avoid unplanned energy supply shortfalls by taking into account impacts due to climate change, forecasted levels of building and transportation electrification, and other factors that can result in those shortfalls.
(F) Comply with paragraph (1) of subdivision (b) of Section 399.13. (G) Strengthen the diversity, sustainability, and resilience of the bulk transmission and distribution systems, and local communities.
(H) Enhance distribution systems and demand-side energy management. (I) Minimize localized air pollutants and other greenhouse gas emissions, with early priority on disadvantaged communities identified pursuant to Section 39711 of the Health and Safety Code.
(2) (A) The commission may authorize all source procurement for electrical corporations load-serving entities that includes various resource types including demand-side resources, supply side resources, and resources that may be either demand-side resources or supply side resources, taking into account the differing electrical corporations’ load-serving entities’ geographic service areas, to ensure that each load-serving entity meets the goals set forth in paragraph (1). (B) The commission may approve procurement of resource types that will reduce the overall emissions of greenhouse gases from the electricity sector and meet the other goals specified in paragraph (1), but due to the nature of the technology or fuel source may not compete favorably in price against other resources over the time period of the integrated resource plan.
(3) In furtherance of the requirements of paragraph (1), the commission shall consider the role of existing renewable generation, grid operational efficiencies, energy storage, and distributed energy resources, including energy efficiency, in helping to ensure each load-serving entity meets energy needs and reliability needs in hours to encompass the hour of peak demand of electricity, excluding demand met by variable renewable generation directly connected to a California balancing authority, as defined in Section 399.12, while reducing the need for new electricity generation resources and new transmission resources in achieving the state’s energy goals at the least cost to ratepayers.
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Resources, to procure diverse clean energy resources, as defined by the commission, that meet the portfolio of resources identified in subdivision (a) of Section 454.51. (5) If the commission requests the Department of Water Resources to procure diverse clean energy resources pursuant to paragraph (4), the commission, in consultation with the Department of Water Resources, shall develop and adopt procedures and requirements that govern procurement by, obligations on, and recovery of costs incurred by, the Department of Water Resources and align with Division 29.5 (commencing with Section 80800) of the Water Code. The commission may review that procurement and, if approved, issue an order governing the recovery of the Department of Water Resources’ costs only if both of the following conditions are satisfied:
(A) The recovery of costs to satisfy the revenue requirement of the Department of Water Resources has been found to be just and reasonable and is in the public interest. (B) The recovery of costs through charges on customers, including, if authorized, the issuance of bonds and the material terms of those bonds, including interest rates, rating, amortization, and maturity, does not unreasonably increase costs to customers on a net present value basis compared with the procurement of diverse clean energy resources by an electrical corporation pursuant to paragraph (4). (b) (1) Each load-serving entity shall prepare and file an integrated resource plan consistent with paragraph (2) of subdivision (a) on a time schedule directed by the commission and subject to commission review.
(2) Each electrical corporation’s plan shall follow Section 454.5. (3) The plan of a community choice aggregator shall be submitted to its governing board for approval and provided to the commission for certification, consistent with paragraph (5) of subdivision (a) of Section 366.2, and shall achieve all of the following:
(A) Economic, reliability, environmental, security, and other benefits and performance characteristics that are consistent with the goals set forth in paragraph (1) of subdivision (a).
(B) A diversified procurement portfolio consisting of both short-term and long-term electricity, electricity-related, and demand reduction products. (C) The resource adequacy requirements established pursuant to Section 380. (4) The plan of an electric service provider shall achieve the goals set forth in paragraph (1) of subdivision (a) through a diversified portfolio consisting of both short-term and long-term electricity, electricity-related, and demand reduction products. (c) To the extent that additional procurement is authorized for the electrical corporation in the integrated resource plan or the procurement process authorized pursuant to Section 454.5, the commission shall ensure that the costs are allocated in a fair and equitable manner to all customers consistent with Section 454.51, that there is no cost shifting among customers of load-serving entities, and that community choice aggregators may self-provide renewable integration resources consistent with Section 454.51. The commission may order resource procurement as a result of the integrated resource planning process and shall enforce any resource procurement requirements on a nondiscriminatory basis.
(d) To eliminate redundancy and increase efficiency, the process adopted pursuant to subdivision (a) shall incorporate, and not duplicate, any other planning processes of the commission.

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(e) This section applies to an electrical cooperative, as defined in Section 2776, only if the electrical cooperative has an annual electrical demand exceeding 700 gigawatthours, as determined based on a three-year average commencing with January 1, 2013.
(f) (1) The commission shall not include the energy, capacity, or any attribute from Diablo Canyon Unit 1 beyond November 1, 2024, or Unit 2 beyond August 26, 2025, in the adopted integrated resource plan portfolios, resource stacks, or preferred system plans.
(2) The commission shall disallow a load-serving entity from including in their adopted integrated resource plan any energy, capacity, or any attribute from the Diablo Canyon Unit 1 beyond November 1, 2024, or Unit 2 beyond August 26, 2025. (g) For a thermal powerplant that uses nuclear fission technology not constructed in the twenty-first century, all resource attributes shall be retired on January 1, 2031, and shall be reported as a separate, line item resource for purposes of complying with Section 398.4.

SEC. 7. Section 454.53 of the Public Utilities Code is amended to read:
454.53. (a) It is the policy of the state that eligible renewable energy resources and zero-carbon resources supply 90 percent of all retail sales of electricity to California end-use customers by December 31, 2035, 95 percent of all retail sales of electricity to California end-use customers by December 31, 2040, 100 percent of all retail sales of electricity to California end-use customers by December 31, 2045, and 100 percent of electricity procured to serve all state agencies by December 31, 2035. The achievement of this policy for California shall not increase carbon emissions elsewhere in the western grid and shall not allow resource shuffling. The commission and Energy Commission, in consultation with the State Air Resources Board, shall take steps to ensure that a transition to a zero-carbon electric system for the State of California does not cause or contribute to greenhouse gas emissions increases elsewhere in the western grid, and is undertaken in a manner consistent with clause 3 of Section 8 of Article I of the United States Constitution. The commission, the Energy Commission, the State Air Resources Board, and all other state agencies shall incorporate this policy into all relevant planning.
(b) The commission, Energy Commission, State Air Resources Board, and all other state agencies shall ensure that actions taken in furtherance of subdivision (a) do all of the following:
(1) Maintain and protect the safety, reliable operation, and balancing of the electric system.
(2) Prevent unreasonable impacts to electricity, gas, and water customer rates and bills resulting from implementation of this section, taking into full consideration the economic and environmental costs and benefits of renewable energy and zero-carbon resources.
(3) To the extent feasible and authorized under law, lead to the adoption of policies and taking of actions in other sectors to obtain greenhouse gas emission reductions that ensure equity between other sectors and the electricity sector. (4) Not affect in any manner the rules and requirements for the oversight of, and enforcement against, retail sellers and local publicly owned utilities pursuant to the California Renewables Portfolio Standard Program (Article 16 (commencing with Section 399.11) of Chapter 2.3) and Sections 454.51, 454.52, 9621, and 9622.

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(5) Not consider the energy, capacity, or any attribute from the Diablo Canyon Unit 1 or Unit 2 powerplant after August 26, 2025, in achieving the policy described in subdivision (a).
(c) Nothing in this section shall affect a retail seller’s obligation to comply with the federal Public Utility Regulatory Policies Act of 1978 (16 U.S.C. Sec. 2601 et seq.).
(d) The commission, Energy Commission, and State Air Resources Board shall do all of the following:
(1) Use programs authorized under existing statutes to achieve the policy described in subdivision (a).
(2) In consultation with all California balancing authorities, as defined in subdivision (d) of Section 399.12, as part of a public process, issue a joint report to the Legislature by January 1, 2021, and at least every four years thereafter. The joint report shall include all of the following:
(A) A review of the policy described in subdivision (a) focused on technologies, forecasts, then-existing transmission, and maintaining safety, environmental and public safety protection, affordability, and system and local reliability. (B) An evaluation identifying the potential benefits and impacts on system and local reliability associated with achieving the policy described in subdivision (a). (C) An evaluation identifying the nature of any anticipated financial costs and benefits to electric, gas, and water utilities, including customer rate impacts and benefits. (D) The barriers to, and benefits of, achieving the policy described in subdivision (a).
(E) Alternative scenarios in which the policy described in subdivision (a) can be achieved and the estimated costs and benefits of each scenario. (3) On or before December 1, 2023, and annually thereafter, in consultation with California balancing authorities, as defined in subdivision (d) of Section 399.12, and as part of, or an interim addendum to, the quadrennial joint report required by paragraph (2), as applicable, issue a joint reliability progress report that reviews system and local reliability within the context of the policy described in subdivision (a), with a particular focus on summer reliability. The joint reliability progress report shall identify challenges and gaps, if any, to achieving system and local reliability and identify the amount and cause of any delays to achieving compliance with all energy and capacity procurement requirements set by the commission.
(e) In a proceeding evaluating the issuance of a certificate of public convenience and necessity for a proposed transmission project, the commission shall establish a rebuttable presumption with regard to need for the proposed transmission project in favor of an Independent System Operator governing board-approved need evaluation if all of the following are satisfied:
(1) The Independent System Operator governing board has made explicit findings regarding the need for the proposed transmission project and has determined that it is the most cost-effective transmission solution.
(2) The Independent System Operator is a party to the proceeding. (3) The Independent System Operator governing board-approved need evaluation is submitted to the commission within sufficient time to be included within the scope of the proceeding.

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(4) The proposed transmission project would clearly satisfy a specific transmission expansion need identified in a decision adopted by the commission recommending resource portfolios to the Independent System Operator for transmission planning.
(5) There has been no substantial change to the scope, estimated cost, or timeline of the proposed transmission project as approved by the Independent System Operator governing board.
(e) Nothing in this section authorizes
(f) This section does not authorize the commission to establish any requirements on a nonmobile self-cogeneration or cogeneration facility that served onsite load, or that served load pursuant to an over-the-fence arrangement if that arrangement existed on or before December 20, 1995.
(f)
(g) This section does not limit any entity, including local governments, from accelerating their achievement of the state’s electric sector decarbonization targets.

SEC. 8. Section 712 of the Public Utilities Code is amended to read:
712. (a) The commission shall convene, or continue, until August 26, 2025, 2030, an independent peer review panel to conduct an independent review of enhanced seismic studies and surveys of the Diablo Canyon Units 1 and 2 powerplant, including the surrounding areas of the facility and areas of nuclear waste storage. (b) The independent peer review panel shall contract with the Energy Commission, the California Geological Survey of the Department of Conservation, the California Coastal Commission, the Alfred E. Alquist Seismic Safety Commission, the Office of Emergency Services, and the County of San Luis Obispo to participate on the panel and provide expertise.
(c) The independent peer review panel shall review the seismic studies and hold public meetings.
(d) The commission shall make reports by the independent peer review panel publicly available on the Internet Web site internet website maintained by the commission.

SEC. 9. Section 712.1 of the Public Utilities Code is amended to read:
712.1. (a) The Legislature finds and declares that in commission Decision 88-12-083 (December 19, 1988) Re Pacific Gas and Electric Company (30 CPUC.2d 189), the commission created the Independent Safety Committee for Diablo Canyon to make recommendations appropriate to enhance the safety of the operation of the Diablo Canyon powerplant.
(b) The Independent Safety Committee for Diablo Canyon is hereby established in the commission and has and shall continue to have the right of the Independent Safety Committee for Diablo Canyon rights established pursuant to commission Decision 88-12-083 88-12-083, as amended by Decisions 07-01-028 and 21-09-003, to conduct annual examinations of the Diablo Canyon powerplant and make additional site visits. The committee shall cease operations no sooner than when the United States Nuclear Regulatory Commission operating permit for the Diablo Canyon powerplant has ceased operations and when all spent nuclear fuel has been moved to dry storage at the Diablo Canyon Independent Spent Fuel Storage Installation. (c) The Independent Safety Committee for Diablo Canyon shall be composed of three experts, one each shall be appointed by the Governor, the Attorney General, UNBACKED 02/08/23 09:11 AM
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and the Chair of the Energy Commission, from a list of candidates nominated by the President of the commission that shall include not more than three qualified candidates as alternatives to the reappointment of the appointing authority’s designated committee member whose term is expiring, and which shall also include the incumbent committee member if the member consents to being an additional candidate. The incumbent as of August 1, 2022, may continue to serve their current term until it expires. (d) The commission shall ensure the funding of the Independent Safety Committee for Diablo Canyon to attract qualified experts during the period of extended operations of the Diablo Canyon powerplant, as defined by Section 712.8. (e) In addition to the duties and responsibilities set forth in commission decisions, the Independent Safety Committee for Diablo Canyon shall do both of the following:
(1) Consult with and incorporate into its assessments and recommendations the independent peer review panel established pursuant to Section 712. (2) Transmit annually its findings and recommendations for improved safety safety, and any response required pursuant to subdivision (f), to the Legislature, the Governor, the commission, the Energy Commission, the United States Nuclear Regulatory Commission, and the company licensed to operate the Diablo Canyon Units 1 and 2. 2 powerplant. The report transmitted to the Legislature shall be in accordance with Section 9795 of the Government Code.
(f) The company licensed to operate the Diablo Canyon Units 1 and 2 powerplant shall annually respond to the annual report provided for in paragraph (2) of subdivision (e) and distribute its response to the governmental entities specified in that paragraph.

SEC. 10. Section 712.8 of the Public Utilities Code is amended to read:
712.8. (a) For purposes of this section, the following definitions apply:
(1) “Current expiration dates” has the same meaning as defined in Section 25548.1 of the Public Resources Code.
(2) “Diablo Canyon powerplant operations” has the same meaning as defined in Section 25548.1 of the Public Resources Code.
(3) “Load-serving entity” has the same meaning as defined in Section 380. (4) “Operator” has the same meaning as defined in Section 25548.1 of the Public Resources Code.
(b) (1) Ordering paragraphs (1) and (14) of commission Decision 18-01-022 (January 11, 2018) Decision Approving Retirement of Diablo Canyon Nuclear Power Plant, are hereby invalidated.
(2) The commission shall reopen commission Application 16-08-006 and take other actions as are necessary to implement this section. (c) (1) (A) Notwithstanding any other law, within 120 days of the effective date of this section, September 2, 2022, the commission shall direct and authorize the operator of the Diablo Canyon Units 1 and 2 to take all actions that would be necessary to operate the powerplant beyond the current expiration dates, so as to preserve the option of extended operations, until the following retirement dates, conditional upon continued authorization to operate by the United States Nuclear Regulatory Commission:
(i) For Unit 1, October 31, 2029.
(ii) For Unit 2, October 31, 2030.
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commission shall modify its order under this paragraph and direct an earlier retirement date.
(C) Actions taken by the operator pursuant to the commission’s actions under this paragraph, including in preparation for extended operations, shall not be funded by ratepayers of any load-serving entities, but may be funded by the loan provided for by Chapter 6.3 (commencing with Section 25548) of Division 15 of the Public Resources Code or other nonratepayer funds available to the operator. The commission shall not allow the recovery from ratepayers of costs incurred by the operator to prepare for, seek, or receive any extended license to operate by the United States Nuclear Regulatory Commission.
(2) (A) No later than December 31, 2023, and notwithstanding the 180-day time limitation in subdivision (b) (a) of Section 25548.2 of the Public Resources Code, the commission shall direct and authorize extended operations at the Diablo Canyon powerplant until the new retirement dates specified in subparagraph (A) of paragraph (1) of subdivision (c). (1).
(B) The commission shall review the reports and recommendations of the Independent Safety Committee for Diablo Canyon described in Section 712.1. If the Independent Safety Committee for Diablo Canyon’s reports or recommendations cause the commission to determine, in its discretion, that the costs of any upgrades necessary to address seismic safety or issues of deferred maintenance that may have arisen due to the expectation of the plant closing sooner are too high to justify incurring, or if the United States Nuclear Regulatory Commission’s conditions of license renewal require expenditures that are too high to justify incurring, the commission may issue an order that reestablishes the current expiration dates as the retirement date, or that establishes new retirement dates that are earlier than provided in subparagraph (A) of paragraph (1), to the extent allowable under federal law, and shall provide sufficient time for orderly shutdown and authorize recovery of any outstanding uncollected costs and fees.
(C) If the loan provided for by Chapter 6.3 (commencing with Section 25548) of Division 15 of the Public Resources Code is terminated under that chapter, the commission may issue an order that reestablishes the current expiration dates as the retirement date, or that establishes new retirement dates that are earlier than provided in subparagraph (A) of paragraph (1), and shall provide sufficient time for orderly shutdown and authorize recovery of any outstanding uncollected costs and fees. (D) If the commission determines that new renewable energy and zero-carbon resources that are adequate to substitute for the Diablo Canyon powerplant and that meet the state’s planning standards for energy reliability have already been constructed and interconnected by the time of its decision, the commission may issue an order that reestablishes the current expiration dates as the retirement date, or that establishes new retirement dates that are earlier than provided in subparagraph (A) of paragraph (1), and shall provide sufficient time for orderly shutdown and authorize recovery of any outstanding uncollected costs and fees.
(E) Any retirement date established under this paragraph shall be conditioned upon continued authorization to operate by the United States Nuclear Regulatory Commission. If the United States Nuclear Regulatory Commission does not extend the current expiration dates or renews the licenses for Diablo Canyon Units 1 or 2 for a period shorter than the extended operations authorized by the commission, the UNBACKED 02/08/23 09:11 AM
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commission shall modify any orders issued under this paragraph to direct a retirement date that is the same as the United States Nuclear Regulatory Commission license expiration date.
(3) The commission shall do all things necessary and appropriate to implement this section, including, but not limited to, allocating financial responsibility for the extended operations of the Diablo Canyon powerplant to customers of all load-serving entities and ensuring completion of funding of the community impacts mitigation settlement described in Section 712.7. The commission shall not require any funds already disbursed or committed under the community impacts mitigation settlement described in Section 712.7 to be returned because of extended operations of the Diablo Canyon powerplant.
(4) Except as authorized by this section, customers of load-serving entities shall have no other financial responsibility for the costs of the extended operations of the Diablo Canyon powerplant. In no event shall load-serving entities other than the operator and their customers have any liability for the operations of the Diablo Canyon powerplant.
(5) Consistent with Section 25548.4 of the Public Resources Code, the commission shall collaborate with the Department of Water Resources to oversee the operator’s actions that are funded by the loan provided for by Chapter 6.3 (commencing with Section 25548) of Division 15 of the Public Resources Code. (d) The commission shall not increase cost recovery from ratepayers for operations and maintenance expenses incurred by the operator during the period from August 1, 2022, to November 2, 2025, 2024, for Diablo Canyon Unit 1 and from August 1, 2022, to August 26, 2025, for Diablo Canyon Unit 2, above the amounts approved in the most recent general rate case for the operator pursuant to commission proceeding A.21-06-021 (June 30, 2021) Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Increase Rates and Charges for Electric and Gas Service Effective on January 1, 2023.
(e) The commission shall order the operator to track all costs associated with continued and extended operations of Diablo Canyon Units 1 and 2. The commission shall authorize the operator to establish accounts as necessary to track all costs incurred under paragraph (1) of subdivision (c), all costs incurred under the loan provided for by Chapter 6.3 (commencing with Section 25548) of Division 15 of the Public Resources Code, all costs to be borne only by the operator’s ratepayers, all costs to be borne by ratepayers of all load-serving entities, consistent with this section, and any other costs as determined by the commission. Among these accounts shall be a Diablo Canyon Extended Operations liquidated damages balancing account, described in subdivisions (g) and (i).
(f) (1) Notwithstanding any approval of extended operations, the commission shall continue to authorize the operator to recover in rates all of the reasonable costs incurred to prepare for the retirement of Diablo Canyon Units 1 and 2, including any reasonable additional costs associated with decommissioning planning resulting from the license renewal applications or license renewals. The reasonable costs incurred to prepare for the retirement of Diablo Canyon Power Plant Units 1 and 2 shall be recovered on a fully nonbypassable basis from customers of all load-serving entities subject to the commission’s jurisdiction in the operator’s service territory, as determined by the commission, except that the reasonable additional costs associated with UNBACKED 02/08/23 09:11 AM
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decommissioning planning resulting from the license renewal applications or license renewals shall be recovered on a fully nonbypassable basis from customers of all load-serving entities subject to the commission’s jurisdiction in the state. (2) The commission shall continue to fund the employee retention program approved in Decision 18-11-024 (December 2, 2018) Decision Implementing Senate Bill 1090 and Modifying Decision 18-01-022, as modified to incorporate 2024, 2025, and additional years of extended operations, on an ongoing basis until the end of operations of both units with program costs tracked under subdivision (e) and fully recovered in rates. Any additional funding for the employee retention program beyond what was already approved in commission Decision 18-11-024 shall be submitted by the operator in an application for review by the commission. (3) The commission shall determine the amount or allocation that the customers of all load-serving entities subject to the commission’s jurisdiction shall contribute towards the reasonable additional costs of decommissioning planning resulting from the license renewal applications or license renewals and shall authorize the operator to recover in rates those costs through a nonbypassable charge applicable to the customers of all load-serving entities subject to the commission’s jurisdiction in the state as set forth in paragraph (1) of subdivision (l). (4) The commission shall authorize the operator to recover in rates all of the reasonable costs incurred to prepare for, respond to, provide information to, or otherwise participate in or engage the independent peer review panel under Section 712. (5) In lieu of a rate-based return on investment and in acknowledgment of the greater risk of outages in an older plant that the operator could be held liable for, the commission shall authorize the operator to recover in rates a volumetric payment equal to six dollars and fifty cents ($6.50), in 2022 dollars, for each megawatthour generated by the Diablo Canyon powerplant during the period of extended operations beyond the current expiration dates, to be borne by customers of all load-serving entities, and an additional volumetric payment equal to six dollars and fifty cents ($6.50), in 2022 dollars, to be borne by customers in the service territory of the operator. The amount of the operating risk payment shall be adjusted annually by the commission using commission-approved escalation methodologies and adjustment factors. (6) (A) In lieu of a rate-based return on investment and in acknowledgment of the greater risk of outages in an older plant that the operator could be held liable for, the commission shall authorize the operator to recover in rates a fixed payment of fifty million dollars ($50,000,000), in 2022 dollars, for each unit for each year of extended operations, subject to adjustment in subparagraphs (B) to (D), inclusive. The amount of the fixed payment shall be adjusted annually by the commission using commission-approved escalation methodologies and adjustment factors. (B) In the first year of extended operations for each unit, the operator shall continue to receive the full fixed payment during periods in which a unit is out of service due to an unplanned outage for nine months or less, and shall receive 50 percent of the payment for months in excess of nine months that a unit is down. (C) In the second year of extended operations, the operator shall continue to receive the fixed payment during periods in which a unit is out of service due to an unplanned outage for eight months or less, and shall receive 50 percent of the payment for months in excess of eight months that a unit is down.

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(D) In each subsequent year of extended operations, the period in which the full fixed payment is received during periods when a unit out is of service due to an unplanned outage shall decline by one additional month. (g) The commission shall authorize and fund as part of the charge under paragraph (1) of subdivision (l), the Diablo Canyon Extended Operations liquidated damages balancing account in the amount of twelve million five hundred thousand dollars ($12,500,000) each month for each unit until the liquidated damages balancing account has a balance of three hundred million dollars ($300,000,000). (h) (1) The commission shall authorize the operator to recover all reasonable costs and expenses necessary to operate Diablo Canyon Units 1 and 2 beyond the current expiration dates, including those in subdivisions (f) and (g), net of market revenues for those operations and any production tax credits of the operator, on a forecast basis in a new proceeding structured similarly to its annual Energy Resource Recovery Account forecast proceeding with a subsequent true-up to actual costs and market revenues for the prior calendar year via an expedited Tier 3 advice letter process, provided that there shall be no further review of the reasonableness of costs incurred if actual costs are below 115 percent of the forecasted costs. All costs shall be recovered as an operating expense and shall not be eligible for inclusion in the operator’s rate base.
(2) As the result of any significant one-time capital expenditures during the extended operation period, the commission may authorize, and the operator may propose, cost recovery of these expenditures as operating expenses amortized over more than one year for the purpose of reducing rate volatility, at an amortization interest rate determined by the commission. The commission shall allow cost recovery if the costs and expenses are just and reasonable. Those costs and expenses are just and reasonable if the operator’s conduct is consistent with the actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time and with information that the operator should have known at the relevant point in time.
(3) If, as a result of the annual true-up for extended operations in paragraph (1), the commission determines that market revenues for the prior year exceeded the annual costs and expenses, including those in subdivisions (f) and (g), the commission shall direct that any available surplus revenues in an account created under subdivision (e) be credited solely to customers in the operator’s service territory. For customers outside the operator’s service territory, market revenues may be credited up to, but not to exceed, their respective annual costs and expenses. If excess funds remain in an account created under subdivision (e) as a result of market revenues exceeding costs and expenses in the final year of the extended operating period, after truing up the final operating year’s market revenues against costs and expenses, the remaining funds shall be the sole source of loan repayment per the requirements provided under Chapter 6.3 (commencing with Section 25548) of Division 15 of the Public Resources Code, except that any federal funds received as described in paragraph (2) (1) of subdivision (b) (c) of Section 25548.3 of the Public Resources Code shall also be used to repay the loan.

Ratepayer funds shall not otherwise be used in any manner to repay the loan provided for under Chapter 6.3 (commencing with Section 25548) of Division 15 of the Public Resources Code.

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(i) (1) During any unplanned outage periods, the commission shall authorize the operator to recover reasonable replacement power costs, if incurred, associated with Diablo Canyon powerplant operations. If the commission finds that replacement power costs incurred when a unit is out of service due to an unplanned outage are the result of a failure of the operator to meet the reasonable manager standard, then the commission shall authorize payment of the replacement power costs from the Diablo Canyon Extended Operations liquidated damages balancing account described in subdivision (g).
(2) After commencing payments from the Diablo Canyon Extended Operations liquidated damages balancing account under the conditions described in paragraph (1), the commission shall authorize the replenishment of the Diablo Canyon Extended Operations liquidated damages balancing account in the amount of twelve million five hundred thousand dollars ($12,500,000) for each unit for each month up to a maximum account balance of three hundred million dollars ($300,000,000). (j) If the commission finds that the operator is requesting recovery of costs that were previously authorized by the commission or other state or federal agency or paid to the operator for cost recovery, the commission may fine the operator an amount up to three times the amount of the penalty provided in Section 2107 for each violation. (k) If at any point during the license renewal process or extended operations period the operator believes that, as a result of an unplanned outage, an emergent operating risk, or a new compliance requirement, the cost of performing upgrades needed to continue operations of one or both units exceed the benefits to ratepayers of the continued operation of doing so, the operator shall promptly notify the commission.

The commission shall promptly review and determine whether expending funds to continue operations is reasonable, will remain beneficial to ratepayers, and is in the public interest or direct the operator to cease operations. The operator shall take all actions necessary to safely operate or maintain the Diablo Canyon powerplant pending the commission determination.
(l) (1) Any costs the commission authorizes the operator to recover in rates under this section shall be recovered on a fully nonbypassable basis from customers of all load-serving entities subject to the commissions’s jurisdiction, as determined by the commission, except as otherwise provided in this section. The recovery of these nonbypassable costs by the load-serving entities shall be based on each customer’s gross consumption of electricity regardless of a customer’s net metering status or purchase of electric energy and service from an electric service provider, community choice aggregator, or other third-party source of electric energy or electricity service. (2) The commission shall establish mechanisms, including authorizing balancing and memorandum accounts and, as needed, agreements with, or orders with respect to, electrical corporations, community choice aggregators, and electric service providers, to ensure that the revenues received to pay a charge or cost payable pursuant to this section are recovered in rates from those entities and promptly remitted to the entity entitled to those revenues.
(m) This section does not alter the recovery of costs, including those previously approved by the commission, to operate Diablo Canyon Units 1 and 2 until the current expiration dates.
(n) The commission shall halt disbursements from the Diablo Canyon Nuclear Decommissioning Non-Qualified Trust, excluding refunds to ratepayers.

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(o) The commission, in consultation with the relevant federal and state agencies and appropriate California Native American tribes, shall, in a new or existing proceeding, determine the disposition of the Diablo Canyon powerplant real property and its surrounding real properties owned by the applicable public utility or any legally related, affiliated, or associated companies, in a manner that best serves the interests of the local community, ratepayers, California Native America tribes, and the state. It is the intent of the Legislature that the existing efforts to transfer lands owned by the operator and Eureka Energy shall not be impeded by the extension of the Diablo Canyon powerplant.
(p) Except as otherwise provided in this section, this section does not alter or limit any proceeding of the commission relating to the decommissioning of the Diablo Canyon powerplant.
(q) The Legislature finds and declares that the purpose of the extension of the Diablo Canyon powerplant operations is to protect the state against significant uncertainty in future demand resulting from the state’s greenhouse-gas-reduction efforts involving electrification of transportation and building energy end uses and regional climate-related weather phenomenon, and to address the risk that currently ordered procurement will be insufficient to meet this supply or that there may be delays in bringing the ordered resources online on schedule. Consequently, the continued operation of Diablo Canyon Units 1 and 2 beyond their current expiration dates shall not be factored into the analyses used by the commission or by load-serving entities not subject to the commission’s jurisdiction when determining future generation and transmission needs to ensure electrical grid reliability and to meet the state’s greenhouse-gas-emissions reduction goals. To the extent the commission decides to allocate any benefits or attributes from extended operations of the Diablo Canyon powerplant, the commission may consider the higher cost to customers in the operator’s service area.
(r) Notwithstanding Section 10231.5 of the Government Code, in coordination with the Energy Commission, the Independent System Operator, and the Department of Water Resources, the commission shall submit, in accordance with Section 9795 of the Government Code, a report to the Legislature each year on the status of new resource additions and revisions to the state’s electric demand forecast, and the impact of these updates on the need for keeping the Diablo Canyon powerplant online. (s)
(r) Any sale, mortgage, transfer of operational control, or any other encumbrance of disposition of the Diablo Canyon powerplant shall continue to be subject to Article 6 (commencing with Section 851).
(t)
(s) (1) The operator shall submit to the commission for its review, on an annual basis the amount of compensation earned under paragraph (5) of subdivision (f), how it was spent, and a plan for prioritizing the uses of such compensation the next year.

Such compensation shall not be paid out to shareholders. Such compensation, to the extent it is not needed for Diablo Canyon, shall be spent to accelerate, or increase spending on, the following critical public purpose priorities:
(A) Accelerating customer and generator interconnections. (B) Accelerating actions needed to bring renewable and zero-carbon energy online and modernize the electrical grid.

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(C) Accelerating building decarbonization.
(D) Workforce and customer safety.
(E) Communications and education.
(F) Increasing resiliency and reducing operational and system risk. (2) The operator shall not earn a rate of return for any of the expenditures described in paragraph (1) so that no profit shall be realized by the operator’s shareholders. Neither the operator nor any of its affiliates or holding company may increase existing public earning per share guidance as a result of compensation provided under this section. The commission shall ensure no double recovery in rates. (u)
(t) The commission shall verify at the conclusion of extended operations that the operator’s sole compensation during the period of extended operations is limited to and in accordance with paragraphs (5) and (6) of subdivision (f) and shall be in lieu of a rate-based return on investment in the Diablo Canyon powerplant. Any excess funds remaining in an account created under subdivision (e) as a result of market revenues exceeding costs and expenses across the extended operating period, after truing up the final operating year’s market revenues against costs and expenses, following loan repayment under paragraph (3) of subdivision (h), shall not be paid out to shareholders. Instead, such excess funds shall be returned in full to customers in a manner to be determined by the commission, except that any funds remaining in the Diablo Canyon Extended Operations liquidated damages balancing account specified in subdivisions (g) and (i), shall be returned to customers in the operator’s service territory in a manner to be determined by the commission. (v)
(u) The efforts to transfer lands owned by the operator and Eureka Energy, including North Ranch, Parcel P, South Ranch, and Wild Cherry Canyon, shall not be impeded by the extension of the operation of the Diablo Canyon powerplant. (w)
(v) In the event of a final determination by the United States Department of Energy that the Diablo Canyon powerplant is not eligible for the Civil Nuclear Credit Program established by Section 18753 of Title 42 of the United States Code, subdivisions (d) to (m), inclusive, (p), (q), (t), and (u) (s), and (t) shall cease to be operative, and the commission shall instead undertake ordinary ratemaking with respect to the Diablo Canyon powerplant.

SEC. 11. Section 913.12 is added to the Public Utilities Code, to read:
913.12. Notwithstanding Section 10231.5 of the Government Code, in coordination with the Energy Commission, the Independent System Operator, and the Department of Water Resources, the commission shall submit a report to the Legislature each year on the status of new resource additions and revisions to the state’s electric demand forecast, and the impact of these updates on the need for keeping the Diablo Canyon powerplant online.

SEC. 12. Section 80710 of the Water Code is amended to read:
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 Backup Assets Program and the Demand Side Grid Support Program.

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(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 only the following facilities:
(A) Extension of the operating life of existing nonnuclear 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 that are located outside of the coastal zone and the jurisdiction of the San Francisco Bay Conservation and Development Commission, of 20 megawatts or more, that are capable of discharging for at least two hours, and with an operational date no later than December 31, 2024. (D) Generation facilities that are located outside of the coastal zone and the jurisdiction of the San Francisco Bay Conservation and Development Commission and use 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, 2024. 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 that use any form of fossil fuel shall only operate as necessary to respond to extreme events, as defined in subdivision (b) of Section 25790.5 of the Public Resources Code, and shall not operate at any other time. (d) 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.
(e) (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 UNBACKED 02/08/23 09:11 AM
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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. (f) 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. (g) (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.
(h) 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.
(i) For contracts entered into pursuant to this division by the department after October 31, 2022, the department shall notify the commission through an investment plan 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 after the commission approves the contract, grant, investment, or loan, investment plan, the executive director of the commission shall give written notice to the Joint Legislative Budget Committee of the action. (j) 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.
(k) 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.

SEC. 13. Section 80713 is added to the Water Code, to read:

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80713. (a) (1) The Public Utilities Commission shall annually assess a capacity payment for the use of the Department of Water Resources Electricity Supply Reliability Reserve Fund established pursuant to Section 80720 by each load-serving entity that fails to meet its system resource adequacy requirements pursuant to Section 380 of the Public Utilities Code during any month in which resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund were used to meet a reliability need. The purpose of the capacity payment is to replenish the Department of Water Resources Electricity Supply Reliability Reserve Fund. The capacity payment is not a penalty and does not prohibit the Public Utilities Commission from assessing a penalty on a load-serving entity for a failure to comply with any resource adequacy requirement.
(2) The capacity payment shall be remitted to the Department of Water Resources Electricity Supply Reliability Reserve Fund by a load-serving entity that fails to meet its system resource adequacy requirements within 30 days of the commission notifying the load-serving entity.
(3) Unless a different calculation methodology is specified pursuant to subdivision (b), the capacity payment for each load-serving entity shall be calculated by the Public Utilities Commission as follows:
(A) A dollar amount equal to the per kilowatt-monthly cost of the resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund, which shall be calculated as the annual cost of the resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund weighted such that two-thirds of that amount reflects the costs of resources procured for summer months, which includes June to September, inclusive, and one-third of that amount reflects the costs of resources procured for other months.
(B) The dollar amount calculated pursuant to subparagraph (A) shall be multiplied by the maximum difference between the load-serving entity’s load and the resources it procured to meet its load during the period in which resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund were used, as determined by the commission with input from the Independent System Operator.
(C) Adjusted to reflect the load-serving entity’s estimated load minus any reductions resulting from any resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund. (D) Adjusted for any resources procured by electrical corporations on behalf of, and paid for by, the load-serving entity.
(b) The Public Utilities Commission, in consultation with the commission, may modify the capacity payment calculation methodology specified in paragraph (3) of subdivision (a). Any modification made by the Public Utilities Commission shall align with any modification made by the commission as authorized by subdivision (b) of Section 80714.

SEC. 14. Section 80714 is added to the Water Code, to read:
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in accordance with Section 9620 of the Public Utilities Code or subdivision (b) of Section 25704.5 of the Public Resources Code, during any month in which resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund were used to meet a reliability need. (2) The capacity payment shall be remitted to the Department of Water Resources Electricity Supply Reliability Reserve Fund by a local publicly owned electric utility that fails to meet its minimum planning reserve margin within 30 days of the executive director notifying the local publicly owned electric utility. (3) Unless a different calculation methodology is specified pursuant to subdivision (b), the capacity payment for each local publicly owned electric utility shall be calculated by the commission as follows:
(A) A dollar amount equal to the per kilowatt-monthly cost of the resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund, which shall be calculated as the annual cost of the resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund weighted such that two-thirds of that amount reflects the costs of resources procured for summer months, which includes June through September, inclusive, and one-third of that amount reflects the costs of resources procured for other months.
(B) The dollar amount calculated pursuant to subparagraph (A) shall be multiplied by the maximum difference between the local publicly owned electric utility’s load and the resources it procured to meet its load during the period in which resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund were used, as determined by the commission with input from the Independent System Operator.
(C) Adjusted to reflect the local publicly owned electric utility’s estimated load minus any reductions resulting from any resources procured using moneys from the Department of Water Resources Electricity Supply Reliability Reserve Fund. (b) The commission, in consultation with the Public Utilities Commission, may modify the capacity payment calculation methodology specified in paragraph (3) of subdivision (a). Any modification made by the commission shall align with any modification made by the Public Utilities Commission as authorized by subdivision (b) of Section 80713.
(c) The commission may adopt regulations to implement this section. In order to ensure the commission implements this section coincident with the Public Utilities Commission’s implementation of Section 80713, thereby ensuring that load-serving entities and local publicly owned electric utilities are treated equally and assessed charges in a similar timeframe, 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 commission action to implement this section.

SEC. 15. Section 80720 of the Water Code is amended to read:
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) or Chapter 5 (commencing with Section 80740) 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.

SEC. 16. Chapter 5 (commencing with Section 80740) is added to Division 29 of the Water Code, to read:

5. 80740. The department shall collect any capacity payment ordered pursuant to Section 80713 or 80714. Payments received shall be deposited into the Department of Water Resources Electricity Supply Reliability Reserve Fund established pursuant to Section 80720 and shall be used solely for the purposes of this division.

SEC. 17. Division 29.5 (commencing with Section 80800) is added to the Water Code, to read:

DIVISION 29.5. CLEAN ENERGY CENTRAL PROCUREMENT

1. 80800. This division does not reduce or modify an electrical corporation’s obligation to serve.
80801. The commission shall issue orders it determines are necessary to carry out this division.
80802. (a) The Legislature finds and declares all of the following:
(1) California has significantly reduced the emissions of greenhouse gases from its electricity sector by fostering the development of renewable and zero-carbon energy resources through the establishment of ambitious goals and policies. These efforts have fundamentally transformed the state’s portfolio of energy resources and the day-to-day operations of the state’s electrical system.

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(2) The state has enabled the expansion of electrical retail choice for customers served in electrical corporation service territory, bringing new market entrants and innovation to California’s evolving retail electricity market. (3) The state’s electrical system also faces the risk of increased disruption due to more frequent and intense extreme weather events fueled by a rapidly changing climate.
(4) For California to achieve its long-term greenhouse gas emission reduction goals, while maintaining a reliable electrical system and providing customers with greater choice in electricity retail providers, the state must establish a new central procurement function within the department that enables the development of a more diverse portfolio of renewable and zero-carbon energy resources. (b) In enacting this division, it is the intent of the Legislature to do all of the following:
(1) Create a central procurement function within the department that would only be exercised upon request by the commission and only if the commission finds that it is necessary to procure diverse clean energy resources beyond those procured by load-serving entities to achieve the state policy specified in Section 454.53 of the Public Utilities Code.
(2) If the department exercises its central procurement function, as described in paragraph (1), provide an opportunity for local publicly owned electric utilities to elect for the department to procure diverse clean energy resources on their behalf. (3) Prohibit the department from selling any energy it acquires pursuant to this division at more than the department’s acquisition costs, including transmission, scheduling, financing, program administration, and other related costs. (4) Prohibit the department from pursuing procurement activities, including, if authorized, the issuance of bonds, except upon a finding from the commission that the recovery of costs through charges on customers, the issuance of bonds, and the material terms of such bonds, including interest rates, rating, amortization, and maturity, do not unreasonably increase costs to customers on a net present value basis compared with procurement of a diverse clean energy resource procured by an electrical corporation. (5) Require the department to prioritize investments that do not compete with the procurement of diverse clean energy resources already planned for development and disclosed by load-serving entities or local publicly owned electric utilities. 80803. The development and operation of a central procurement function program as provided in this division is in all respects for the welfare and benefit of the people of the state, to protect the public peace, health, and safety, and constitutes an essential government purpose.
80804. This division shall be liberally construed in a manner so as to effectuate its purposes and objectives.
80805. (a) The powers and responsibilities of the department established pursuant to this division are separate from, and not governed by, the provisions relating to the State Water Resources Development System, including, but not limited to, those powers and responsibilities granted pursuant to Part 3 (commencing with Section 11100) of Division 6 and the California Water Resources Development Bond Act (Chapter 8 (commencing with Section 12930) of Part 6 of Division 6).

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(b) The Clean Energy Central Procurement Fund established in Section 80830, and the moneys in that fund, are separate and distinct from any other fund and moneys administered by the department.
(c) This division does not subject the department to the jurisdictional authority of the Public Utilities Commission or expand the jurisdiction of the Public Utilities Commission, including that state water resources development system facilities subject to the California Water Resources Development Bond Act (Chapter 8 (commencing with Section 12930) of Part 6 of Division 6) and the department’s other electrical generation projects or power contracts outside of those funded through the Clean Energy Central Procurement Fund, remain outside the jurisdiction of the commission. 80806. The department may adopt regulations for purposes of administering this division.

2. 80810. For purposes of this division, the following definitions apply:
(a) “Balancing authority area” means the collection of generation, transmission, and loads within the metered boundaries of a balancing area within California. The balancing authority maintains load resource balance within this area. (b) “Bond” means any bond, note, or other written evidence of indebtedness issued solely for purposes of supporting the Clean Energy Central Procurement Fund and other related expenses incurred by the department pursuant to this division, or for reimbursing expenditures from the fund for those purposes, establishing or maintaining reserves in connection with a bond, costs of issuance of a bond or incidental to its payment or security, capitalized interest, or renewing or refunding any bonds. (c) “Commission” means the Public Utilities Commission. (d) “Electrical corporation” has the same meaning as defined in Section 218 of the Public Utilities Code.
(e) “Energy Commission” means the State Energy Resources Conservation and Development Commission.
(f) “Fund” means the Clean Energy Central Procurement Fund established in Section 80830.
(g) “Independent System Operator” means the Independent System Operator described in Article 3 (commencing with Section 345) of Chapter 2.3 of Part 1 of Division 1 of the Public Utilities Code.
(h) “Load-serving entity” has the same meaning as defined in Section 380 of the Public Utilities Code.
(i) “Local publicly owned electric utility” has the same meaning as defined in Section 224.3 of the Public Utilities Code.

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the department may conduct those solicitations. The purpose of these competitive solicitations is to make available to the state diverse clean energy resources that meet criteria determined by the commission, which shall include, but not be limited to, energy resources that have a first point of interconnection with the transmission grid or the distribution grid within a balancing authority area. (b) In evaluating the bids received through the solicitation, the department shall consider all of the following:
(1) For diverse clean energy resources dependent on the development of a project, that project’s viability, including, but not limited to, developer experience, developer financial strength and creditworthiness sufficient to eliminate financing contingencies, and the status of required permits and licenses.
(2) The ability to meet in-service dates offered during the solicitation and the ability to meet those in-service dates without escalation in cost. (3) The useful life of the project.
(4) The capability to supply energy, capacity, and ancillary services at locations, times of day, and for durations that meet the state’s energy resource needs, as determined by the department and the commission.
(5) Any other criteria determined by the commission or the department. 80821. (a) When conducting a procurement pursuant to Section 80820, the department shall confer with the commission and other parties, including local publicly owned electric utilities participating pursuant to Section 80822, for diverse clean energy resource procurement activities of an identified scope and duration. The department shall recover costs related to conducting the requested solicitations and all supporting work. Cost recovery may be effectuated, if determined to be appropriate by the commission, through a nonbypassable charge approval process or pursuant to Section 80822 for local publicly owned electric utilities.
(b) If cost recovery is determined through a commission proceeding, the department shall recover its costs if the commission determines those costs are just and reasonable. Those costs may include costs related to bond issuance incurred pursuant to Chapter 5 (commencing with Section 80840), costs related to contracting for diverse clean energy resources, and other costs to implement this division. (c) If the commission determines that a nonbypassable charge necessary to fund activities conducted by the department pursuant to this division is just and reasonable, the department shall ensure it has entered into an agreement with the commission for that nonbypassable charge before it begins to incur costs related to a specific activity under this division. If the purpose of the nonbypassable charge is to recover the department’s revenue requirement related to bond issuance debt service, the department shall ensure the agreement has the force and effect of an irrevocable financing order adopted in accordance with Article 5.5 (commencing with Section 840) of Chapter 4 of Part 1 of Division 1 of the Public Utilities Code or that the commission has separately issued an irrevocable financing order related to the nonbypassable charge. (d) Any agreement between the department and the commission under this section shall provide for the administration of the nonbypassable charge, including both of the following requirements:
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collections above or below the revenue requirement. The commission shall adjust charges in the subsequent year to reflect that excess or deficiency. (2) During any period, if the department forecasts that the revenue requirement for that period will not be met and that collections will not be sufficient to fund any of the amounts specified in Section 80842 or subdivision (b) of Section 80830, the department shall notify the commission in writing and the commission shall act within 60 days of receiving that notice to increase the nonbypassable charge so that the amounts collected during that period are sufficient to meet those obligations. (e) Any agreement between the department and the commission pursuant to this section that is solely for the purpose of imposing a nonbypassable charge to recover the department’s revenue requirement related to bond issuance debt service shall include a provision stating that the commission’s just and reasonable determination with respect to the revenue requirement is in effect for the duration of the bond term. 80822. (a) Pursuant to Section 80820, the department may establish a schedule and mechanism for any local publicly owned electric utility to voluntarily obtain from the department energy, capacity, or ancillary services to be acquired by the department through its central procurement function on a contract-by-contract basis. (b) In order to voluntarily participate, a local publicly owned electric utility shall commit to the imposition of a nonbypassable charge on its ratepayers sufficient at all times to fund its participation in the program and on terms and conditions as set forth in Section 80826.
80823. At the request of the department, the commission may order an electrical corporation, or its successor in the performance of a related service, to transmit or provide for the transmission of, and distribute all electricity made available by the department, and, as agent of the department, provide billing, collection, and other related services on terms and conditions that reasonably compensate the electrical corporation for its services and adequately secure payment to the department. 80824. The commission may issue rules regulating the enforcement of the agency function pursuant Section 80823 and this division, including collection of nonbypassable charges and payment into the fund on behalf of the department. 80825. (a) If the department has executed an agreement with the commission pursuant to subdivision (c) of Section 80821, the department may recover, as a revenue requirement, in the amounts and at the times necessary to enable it to comply with Section 80842, and shall advise the commission and each applicable local publicly owned electric utility, as the department determines to be appropriate and subject to the terms of the agreement.
(b) For purposes of this division and except as otherwise provided in this section, the commission’s authority as set forth in Section 451 of the Public Utilities Code shall apply.
80826. (a) A local publicly owned electric utility that voluntarily participates in the department’s central procurement function pursuant to Section 80822 shall enter into an agreement with the department for the revenue requirement to fund its participation and that agreement shall have the force and effect of an irrevocable financing order.
(b) The agreement shall provide for the administration of the revenue requirement, including both of the following:

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(1) A requirement that the department annually notify the local publicly owned electric utility of the annual collections received by the department with respect to the revenue requirement and the amount of any excess or deficiency in collections above or below the revenue requirement. The local publicly owned electric utility shall adjust charges in the subsequent year to reflect any such excess or deficiency. (2) During any revenue requirement period, a requirement that, if the department forecasts that the revenue requirement for that period will not be met and that collections will not be sufficient to fund any of the amounts described in Section 80842, the department notify the local publicly owned electric utility in writing and the local publicly owned electric utility shall act within 30 days of receiving that notice to increase the charge so that the amount collected during the period are sufficient to meet those obligations.
80827. All moneys collected by load-serving entities and remitted to the department for any diverse clean energy resources acquired and sold pursuant to this division, and all moneys paid directly or indirectly to or for the account of the department for any sale, exchange, transfer, or disposition of energy acquired pursuant to this division, shall be deposited into the fund in accordance with Section 80830. 80828. The department may fix and establish the procedure and charges for the sale or other disposal of energy purchased by the department.

4. 80830. (a) There is hereby established in the State Treasury the Clean Energy Central Procurement Fund. Notwithstanding Section 13340 of the Government Code, all moneys in the fund are continuously appropriated, without regard to fiscal year, to the department and shall be available for purposes of this division. (b) All revenues payable to the department under this division, including proceeds of bonds issued pursuant to Chapter 5 (commencing with Section 80840), shall be deposited into the fund. Notwithstanding any other law, interest accruing on the moneys in the fund shall be deposited into the fund and shall be used for purposes of this division.
(c) Payments from the fund may be made only for the following purposes:
(1) Payment of any bonds or other contractual obligations authorized by this division.
(2) The cost of energy and transmission, scheduling, and other related expenses incurred by the department.
(3) The expenses incurred by the department in administering this division, including costs of personnel, contracts, or arrangements to carry out the department’s duties and responsibilities pursuant to this division.
(d) Obligations authorized pursuant to this division shall be payable solely from the fund. Neither the full faith and credit nor the taxing power of the state are, or may be, pledged for any payment under any obligation authorized by this division. (e) While any obligations of the department incurred pursuant to this division remain 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 UNBACKED 02/08/23 09:11 AM
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obligations. The department may include this pledge and undertaking of the state in the department’s obligations.

5. 80840. (a) (1) If the commission requests the department to engage in central procurement activities pursuant to paragraph (5) of subdivision (a) of Section 454.52 of the Public Utilities Code, due to the timing of cost recovery processes, the department may determine that it is necessary or desirable to issue bonds to support activities for the procurement of diverse clean energy resources pursuant to this division. (2) Upon making a determination pursuant to paragraph (1), the department may issue bonds for purposes of financing the procurement of diverse clean energy resources supporting the fund and other related expenses incurred by the department pursuant to this division, and subsequent to the department having entered into an agreement with the commission regarding a revenue requirement. Bonds shall not be issued in an amount the debt service on which, to the extent payable from the fund, is estimated by the department to exceed the amounts estimated to be available in the fund for their payment.
(b) Before the issuance of bonds in a public offering, the department shall ensure the bonds have an investment grade rating from at least one nationally recognized investment ratings firm and the document authorizing the issuance of the bonds shall provide for repayment from pledged revenues.
(c) The commission shall have an opportunity to review the trust agreement or other document pursuant to which the bonds are issued and revenues are pledged, and shall consult with the department regarding the trust agreement or other document, to ensure its consistency with the revenue requirement agreement between the department and commission.
(d) In addition to any other purposes for which bonds may be issued pursuant to this division, bonds may be issued for the following purposes:
(1) Refunding bonds to obtain a lower interest rate.
(2) Refunding bonds bearing a variable interest rate with bonds bearing interest at a fixed rate.
(3) Refunding bonds if a nationally recognized investment ratings firm reduces or withdraws, or proposes to reduce or withdraw, the rating assigned to securities that are secured by bond insurance policies, credit, or liquidity facilities issued by the provider of a bond insurance policy, or a credit or liquidity facility securing the bonds being refunded.
(4) Refunding bonds issued to preserve a federal income tax exemption or to qualify or maintain other federal income tax benefits.
80841. (a) Whenever the director determines that the issuance of bonds is necessary or desirable to accomplish the goals set forth in this division, including financing the procurement of diverse clean energy resources, the director shall issue a written determination authorizing the issuance of bonds by the department. The department, in consultation with the Department of Finance, shall notify the Chairperson of the Joint Legislative Budget Committee and the chairpersons of the fiscal committees of each house of the Legislature of its written determination. The bonds shall be sold in the manner, and on the terms and conditions, specified in that determination, and UNBACKED 02/08/23 09:11 AM
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the determination may contain or authorize any other provision, condition, or limitation not inconsistent with this division and those provisions as may be deemed reasonable and proper for the security of the bondholders. Bonds may mature at the time or times, and bear interest at the rate or rates, which may be fixed or variable and be determined by reference to an index or such other method, and may be federally tax exempt, as specified in the determination. Neither the person executing the determination to issue bonds nor any person executing bonds shall be personally liable therefor or be subject to any personal liability or accountability by reason of the issuance of the bonds. (b) In the discretion of the department, bonds may be secured by a trust agreement by and between the department and a trustee, which may be any trust company or bank having trust powers within or outside the state, or the Treasurer. Notwithstanding any other law, the Treasurer shall not be deemed to have a conflict of interest by reason of acting as the trustee. The department may enter into contracts or arrangements in connection with the issuance and sale of bonds, or with respect to any outstanding bonds for so long as those bonds remain outstanding, as it shall deem to be necessary or desirable for the issuance and further security of the bonds, including, but not limited to, credit enhancement agreements, dealer agreements, purchase contracts, escrow agreements, and similar arrangements.
(c) Bonds shall be legal investments for all trust funds, the funds of all insurance companies, savings and commercial banks, trust companies, executors, administrators, trustees, and other fiduciaries, for state school funds, pension funds, and for any funds that may be invested in county, school, or municipal bonds. (d) Notwithstanding that bonds may be payable from a special fund, the bonds shall be deemed to be negotiable instruments for all purposes. (e) Any bonds, and the transfer of and income derived from those bonds, shall at all times be free from taxation of every kind by the state and by the political subdivisions of the state.
(f) Bonds shall not be deemed to constitute a debt or liability of the state or of any political subdivision thereof, other than the department, or a pledge of the full faith and credit of the state or of any such political subdivision, but shall be payable solely from the revenues described in paragraph (1) of subdivision (g). All bonds shall contain a statement to the following effect: “Neither the faith and credit nor the taxing power of the State of California is pledged to the payment of the principal of or interest on this bond.” The issuance of bonds shall not directly or indirectly or contingently obligate the state or any political subdivision thereof to levy or to pledge any form of taxation whatever therefor or to make any appropriation for their payment. (g) (1) The department may pledge and apply all or any part of revenues of any nature whatever accruing to the department, from orders issued, charges imposed, or contracts entered into pursuant to or in furtherance of this division, or the right to receive the same, to the payment or security of any or all of the principal of the bonds or the interest thereon, in the manner and upon terms that the department deems advisable.
(2) (A) It is the intent of the Legislature that any pledge of moneys, revenues, or property made by the department shall be valid and binding from the time when the pledge is made; that the moneys, revenues, or property so pledged and thereafter collected from retail end use customers, or paid directly or indirectly to or for the UNBACKED 02/08/23 09:11 AM
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account of the department, is hereby made, and shall immediately be, subject to the lien of that pledge without any physical delivery thereof or further act. (B) It is the intent of the Legislature that the lien of any such pledge shall be valid and binding against all parties having claims of any kind in tort, contract, or otherwise against the department irrespective of whether those parties have notice thereof, and that no resolution or instrument by which the pledge or lien created pursuant to this subdivision is expressed, confirmed, or approved need be filed or recorded in order to perfect the pledge or lien.
(C) It is the intent of the Legislature that this paragraph, in all respects, govern the creation, perfection, priority, and enforcement of any lien created pursuant to this division.
80842. (a) The department shall, and in any obligation entered into pursuant to this division may covenant to, at least annually, and more frequently as required, establish and revise revenue requirements sufficient, together with any moneys deposited into the fund, to provide all of the following:
(1) The amounts necessary to pay the principal of, and premium, if any, and interest on, all bonds as and when the same shall become due. (2) The amounts necessary to pay for electricity purchased by it and to deliver it to purchasers, including the cost of electricity, transmission, scheduling, and other related expenses incurred by the department, or to make payments under any other contracts, agreements, or obligations entered into by it pursuant to this division, in the amounts and at the times the same shall become due.
(3) Reserves in amount as may be determined by the department from time to time to be necessary or desirable.
(4) The pooled money investment rate on funds advanced for electricity purchases before the receipt of payment for those purchases by the purchasing entity. (5) The administrative costs of the department and other state agencies, including the costs and fees for professional services, bond issuance and sale, and other miscellaneous costs, incurred in connection with the issuance of bonds or the administration of this division.
(b) The department shall notify the commission of its revenue requirement pursuant to the agreement required pursuant to Section 80821 and that revenue requirement shall be satisfied by the recovery of its costs through a nonbypassable charge.

SEC. 18. The Legislature finds and declares that a special statute is necessary and that a general statute cannot be made applicable within the meaning of Section 16 of Article IV of the California Constitution because of the unique circumstances impacting the Diablo Canyon powerplant, as described in Chapter 6.3 (commencing with Section 25548) of Division 15 of the Public Resources Code.

SEC. 19. No reimbursement is required by this act pursuant to Section 6 of Article XIII B of the California Constitution because the only 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 XIII B of the California Constitution.

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SEC. 20. 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.
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AMENDED IN ASSEMBLY APRIL 13, 2023
california legislature—2023–24 regular session
ASSEMBLY BILL No. 1373
Introduced by Assembly Member Garcia
February 17, 2023
An act to amend and repeal Section 25216.7 of the Public Resources Code, relating to energy. An act to amend Section 10295.6 of the Public Contract Code, to amend Sections 365.1, 380, 454.51, and 454.52 of the Public Utilities Code, and to amend Section 80720 of, to add Sections 80713 and 80714 to, to add Chapter 5 (commencing with Section 80740) to Division 29 of, and to add Division 29.5 (commencing with Section 80800) to, the Water Code, relating to energy, and making an appropriation therefor.
legislative counsel’s digest
AB 1373, as amended, Garcia. Energy: firm zero-carbon resources.

Energy.
(1) Existing law requires the Public Utilities Commission (PUC) to identify a diverse and balanced portfolio of resources needed to ensure a reliable electricity supply that provides optimal integration of renewable energy in a cost-effective manner. Existing law requires the PUC to adopt a process for each load-serving entity, as defined, to file an integrated resource plan and a schedule for periodic updates to the plan, and to ensure that load-serving entities meet other specified requirements.

This bill would require that the portfolio of resources ensure a reliable electricity supply that also provides optimal integration of resource diversity in a cost-effective manner, as specified. The bill would authorize the PUC to direct an electrical corporation, and request the

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Department of Water Resources, to procure diverse clean energy resources, as defined by the PUC, that satisfy the portfolio of resources, as specified. The bill would authorize the PUC to order resource procurement as a result of the integrated resource planning process and require the PUC to enforce any resource procurement requirements on a nondiscriminatory basis.
(2) Existing law establishes the Department of Water Resources Electricity Supply Reliability Reserve Fund and continuously appropriates moneys in the fund to the department for purposes of implementing projects, purchases, and contracts to carry out specified purposes, including, but not limited to, the Distributed Electricity Backup Assets Program and the Demand Side Grid Support Program.

This bill would require the PUC to annually assess a capacity payment for the use of the fund by each load-serving entity that fails to meet its system resource adequacy requirements during a month in which resources procured using moneys from the fund were used to meet a reliability need. The bill would require the executive director of the Energy Commission to annually assess a capacity payment for the use of the fund by each local publicly owned electric utility that fails to meet its minimum planning reserve margin during a month in which resources procured using moneys from the fund were used to meet a reliability need, and authorize the Energy Commission to adopt regulations for this purpose, as specified. The bill would require the department to collect any capacity payment ordered pursuant to those requirements and to deposit those payments into the fund, thereby making an appropriation.

This bill would authorize the department, following a determination from the PUC, in consultation with the Energy Commission and the Independent System Operator, that it is necessary for the department to develop and conduct one or more competitive solicitations to procure energy, capacity, ancillary services, and all associated attributes, to conduct those solicitations, as specified. The bill would authorize the department to establish a schedule and mechanism for any local publicly owned electric utility to voluntarily obtain from the department energy, capacity, or ancillary services to be acquired by the department through its central procurement function on a contract-by-contract basis. At the request of the department, the bill would authorize the PUC to order an electrical corporation to provide for the transmission of and distribute all electricity made available by the department, and, as an agent of the department, to provide billing, collection, and other related 98 AB 1373 — 2 —
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services on terms and conditions that reasonably compensate the electrical corporation for its services and adequately secure payment to the department. The bill would establish the Clean Energy Central Procurement Fund and continuously appropriate moneys in the fund to the department for specified purposes. By establishing a continuously appropriated fund, the bill would make an appropriation. The bill would require that all moneys collected by load-serving entities and remitted to the department with respect to certain diverse clean energy resources, and all moneys paid directly or indirectly to the department with respect to the sale, exchange, transfer, or disposition of certain energy, be deposited into the fund. The bill would authorize the department, upon determining that it is necessary or desirable to issue bonds to support activities for the procurement of diverse clean energy resources, to issue bonds for purposes of, among other things, financing the procurement of diverse clean energy resources supporting the fund and other related expenses incurred by the department, as specified. The bill would authorize the department to adopt regulations for purposes of administering these provisions.
(3) 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 certain of the above provisions would be part of the act and a violation of a PUC action implementing this bill’s requirements would be a crime, the bill would impose a state-mandated local program.

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 a specified reason.

Existing law requires the State Energy Resources Conservation and Development Commission (Energy Commission), in consultation with the Public Utilities Commission, the Independent System Operator, and the State Air Resources Board, on or before December 31, 2023, to submit to the Legislature an assessment of the firm zero-carbon resources that support a clean, reliable, and resilient electrical grid in California and will achieve the policy of the state that eligible renewable energy resources and zero-carbon resources supply 100% of all retail sales of electricity to California end-use customers and 100% of electricity procured to serve all state agencies by December 31, 2045, 98 — 3 — AB 1373
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as specified. Existing law requires that the assessment, among other things, evaluate the use of energy storage to achieve those goals.

This bill would require the assessment to instead be submitted on or before June 30, 2024, and would limit the requirement to evaluate the use of energy storage in the assessment to an evaluation of the use of long-duration and multiday energy storage.

Vote: majority. Appropriation: no yes. Fiscal committee: yes.

State-mandated local program: no yes.

The people of the State of California do enact as follows:
line 1 SECTION 1. Section 10295.6 of the Public Contract Code is line 2 amended to read:
line 3 10295.6. Sections 10295 and 10297 do not apply to any contract line 4 entered into by the Department of Water Resources under Part 3 line 5 (commencing with Section 11100) of Division 6 or 6, Chapter 8 line 6 (commencing with Section 12930) of Part 6 of Division 6 6, line 7 Division 29 (commencing with Section 80700), or Division 29.5 line 8 (commencing with Section 80800), of the Water Code for the line 9 acquisition, sale, or transmission of power, or for services to line 10 facilitate those activities.
line 11 SEC. 2. Section 365.1 of the Public Utilities Code is amended line 12 to read:
line 13 365.1. (a)  Except as expressly authorized by this section, and line 14 subject to the limitations in subdivisions (b) and (c), the right of line 15 retail end-use customers pursuant to this chapter to acquire service line 16 from other providers is suspended until the Legislature, by statute, line 17 lifts the suspension or otherwise authorizes direct transactions. For line 18 purposes of this section, “other provider” means any person, line 19 corporation, or other entity that is authorized to provide electric line 20 service within the service territory of an electrical corporation line 21 pursuant to this chapter, and includes an aggregator, broker, or line 22 marketer, as defined in Section 331, and an electric service line 23 provider, as defined in Section 218.3. “Other provider” does not line 24 include a community choice aggregator, as defined in Section line 25 331.1, and the limitations in this section do not apply to the sale line 26 of electricity by “other providers” to a community choice line 27 aggregator for resale to community choice aggregation electricity line 28 consumers pursuant to Section 366.2.
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line 1 (b)  The commission shall allow authorize individual retail line 2 nonresidential end-use customers to acquire electric service from line 3 other providers in each electrical corporation’s distribution service line 4 territory, up to a maximum allowable total kilowatthours annual line 5 limit. The maximum allowable annual limit shall be established line 6 by the commission for each electrical corporation at the maximum line 7 total kilowatthours supplied by all other providers to distribution line 8 customers of that electrical corporation during any sequential line 9 12-month period between April 1, 1998, and the effective date of line 10 this section. October 11, 2009. Within six months of the effective line 11 date of this section, or by July 1, 2010, whichever is sooner, the line 12 October 11, 2009, the commission shall adopt and implement a line 13 reopening schedule that commences immediately and will phase line 14 in the allowable amount of increased kilowatthours over a period line 15 of not less than three years, and not more than five years, raising line 16 the allowable limit of kilowatthours supplied by other providers line 17 in each electrical corporation’s distribution service territory from line 18 the number of kilowatthours provided by other providers as of the line 19 effective date of this section, October 11, 2009, to the maximum line 20 allowable annual limit for that electrical corporation’s distribution line 21 service territory. The commission shall review and, if appropriate, line 22 modify its currently effective rules governing direct transactions, line 23 but that review shall not delay the start of the phase-in schedule. line 24 (c)  Once the commission has authorized additional direct line 25 transactions pursuant to subdivision (b), it shall do both of the line 26 following:
line 27 (1)  Ensure that other providers are subject to the same line 28 requirements that are applicable apply to the state’s three largest line 29 electrical corporations under any programs or rules adopted by the line 30 commission to implement the resource adequacy provisions of line 31 Section 380, the renewables portfolio standard provisions of Article line 32 16 (commencing with Section 399.11), and the requirements for line 33 the electricity sector adopted by the State Air Resources Board line 34 pursuant to the California Global Warming Solutions Act of 2006 line 35 (Division 25.5 (commencing with Section 38500) of the Health line 36 and Safety Code). Code), and the requirements of the integrated line 37 resource planning process as specified in Sections 454.5 to 454.6, line 38 inclusive. This requirement applies notwithstanding any prior line 39 decision of the commission to the contrary.
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line 1 (2)  (A)  Ensure that, in the event that the commission authorizes, line 2 in the situation of a contract with a third party, or orders, in the line 3 situation of utility-owned generation, an electrical corporation to line 4 obtain generation resources that the commission determines are line 5 needed to meet system or local area reliability needs for the benefit line 6 of all customers in the electrical corporation’s distribution service line 7 territory, the net capacity costs of those generation resources are line 8 allocated on a fully nonbypassable basis consistent with departing line 9 load provisions as determined by the commission, to all of the line 10 following:
line 11 (i)  Bundled service customers of the electrical corporation. line 12 (ii)  Customers that purchase electricity through a direct line 13 transaction with other providers.
line 14 (iii)  Customers of community choice aggregators. line 15 (B)  If the commission authorizes or orders an electrical line 16 corporation to obtain generation resources pursuant to subparagraph line 17 (A), the commission shall ensure that those resources meet a system line 18 or local reliability need in a manner that benefits all customers of line 19 the electrical corporation. The commission shall allocate the costs line 20 of those generation resources to ratepayers in a manner that is fair line 21 and equitable to all customers, whether they receive electric service line 22 from the electrical corporation, a community choice aggregator, line 23 or an electric service provider.
line 24 (C)  The resource adequacy benefits of generation resources line 25 acquired by an electrical corporation pursuant to subparagraph (A) line 26 shall be allocated to all customers who pay their net capacity costs. line 27 Net capacity costs shall be determined by subtracting the energy line 28 and ancillary services value of the resource from the total costs line 29 paid by the electrical corporation pursuant to a contract with a line 30 third party or the annual revenue requirement for the resource if line 31 the electrical corporation directly owns the resource. An energy line 32 auction shall not be required as a condition for applying this line 33 allocation, but may be allowed as a means to establish the energy line 34 and ancillary services value of the resource for purposes of line 35 determining the net costs of capacity to be recovered from line 36 customers pursuant to this paragraph, and the allocation of the net line 37 capacity costs of contracts with third parties shall be allowed for line 38 the terms of those contracts.
line 39 (D)  It is the intent of the Legislature, in enacting this paragraph, line 40 to provide additional guidance to the commission with respect to 98 AB 1373 — 6 —
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line 1 the implementation of subdivision (g) of Section 380, as well as line 2 and to ensure that the customers to whom the net costs and benefits line 3 of capacity are allocated are not required to pay for the cost of line 4 electricity they do not consume.
line 5 (d)  (1)  If the commission approves a centralized resource line 6 adequacy mechanism pursuant to subdivisions (h) and (i) of Section line 7 380, upon the implementation of the centralized resource adequacy line 8 mechanism the requirements of paragraph (2) of subdivision (c) line 9 shall be suspended. If the commission later orders that electrical line 10 corporations cease procuring capacity through a centralized line 11 resource adequacy mechanism, the requirements of paragraph (2) line 12 of subdivision (c) shall again apply.
line 13 (2)  If the use of a centralized resource adequacy mechanism is line 14 authorized by the commission and has been implemented as set line 15 forth in paragraph (1), the net capacity costs of generation resources line 16 that the commission determines are required to meet urgent system line 17 or urgent local grid reliability needs, and that the commission line 18 authorizes to be procured outside of the Section 380 or Section line 19 454.5 processes, shall be recovered according to the provisions of line 20 paragraph (2) of subdivision (c).
line 21 (3)  This subdivision does not supplant the resource adequacy line 22 requirements of Section 380 or the resource procurement line 23 procedures established in Section 454.5.
line 24 (e)  On or before June 1, 2019, the commission shall issue an line 25 order regarding direct transactions that provides as follows:
line 26 (1)  Increase the maximum allowable total kilowatthours annual line 27 limit by 4,000 gigawatthours and apportion that increase among line 28 the service territories of the electrical corporations. line 29 (2)  All residential and nonresidential customer accounts that line 30 are on direct access as of January 1, 2019, remain authorized to line 31 participate in direct transactions.
line 32 (f)  (1)  On or before June 1, 2020, the commission shall provide line 33 recommendations to the Legislature on implementing a further line 34 direct transactions reopening schedule, including, but not limited line 35 to, the phase-in period over which the further direct transactions line 36 shall occur for all remaining nonresidential customer accounts in line 37 each electrical corporation’s service territory. line 38 (2)  In developing the recommendations pursuant to paragraph line 39 (1), the commission shall find all of the following:
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line 1 (A)  The recommendations are consistent with the state’s line 2 greenhouse gas emission reduction goals.
line 3 (B)  The recommendations do not increase emissions of criteria line 4 air pollutants and toxic air contaminants.
line 5 (C)  The recommendations ensure electrical system reliability. line 6 (D)  The recommendations do not cause undue shifting of costs line 7 to bundled service customers of an electrical corporation or to line 8 direct transaction customers.
line 9 (3)  (A)  The recommendations shall be provided in compliance line 10 with Section 9795 of the Government Code.
line 11 (B)  Pursuant to Section 10231.5 of the Government Code, this line 12 subdivision is inoperative on June 1, 2024.
line 13 SEC. 3. Section 380 of the Public Utilities Code is amended line 14 to read:
line 15 380. (a)  The commission, in consultation with the Independent line 16 System Operator, shall establish resource adequacy requirements line 17 for all load-serving entities.
line 18 (b)  In establishing resource adequacy requirements, the line 19 commission shall ensure the reliability of electrical service in line 20 California while advancing, to the extent possible, the state’s goals line 21 for clean energy, reducing air pollution, and reducing emissions line 22 of greenhouse gases. The resource adequacy program shall achieve line 23 all of the following objectives:
line 24 (1)  Facilitate development of new generating, nongenerating, line 25 and hybrid capacity and retention of existing generating, line 26 nongenerating, and hybrid capacity that is economic economical line 27 and needed. needed for reliability and to achieve the state policy line 28 specified in Section 454.53.
line 29 (2)  Establish new, or maintain existing, demand response line 30 products and tariffs that facilitate the economic economical line 31 dispatch and use of demand response that can either meet or reduce line 32 an electrical corporation’s resource adequacy requirements, as line 33 determined by the commission.
line 34 (3)  Equitably allocate the cost of generating capacity and line 35 demand response in a manner that prevents the shifting of costs line 36 between customer classes.
line 37 (4)  Minimize enforcement requirements and costs. line 38 (5)  Maximize the ability of community choice aggregators to line 39 determine the generation resources used to serve their customers. 98 AB 1373 — 8 —
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line 1 (c)  Each load-serving entity shall maintain physical generating line 2 capacity and electrical demand response adequate to meet its load line 3 requirements, including, but not limited to, peak demand and line 4 planning and operating reserves. The generating capacity or line 5 electrical demand response shall be deliverable to locations and line 6 at times as may be necessary to maintain electrical service system line 7 reliability, local area reliability, and flexibility. line 8 (d)  Each load-serving entity shall, at a minimum, meet the most line 9 recent minimum planning reserve and reliability criteria approved line 10 by the board of directors of the Western Systems Coordinating line 11 Council or the Western Electricity Coordinating Council. line 12 (e)  The commission shall implement and enforce the resource line 13 adequacy requirements established in accordance with this section line 14 in a nondiscriminatory manner. Each load-serving entity shall be line 15 subject to the same requirements for resource adequacy and line 16 adequacy, the renewables portfolio standard program program, line 17 and the integrated resource planning process pursuant to Section line 18 454.52 that are applicable apply to electrical corporations pursuant line 19 to this section, or otherwise required by law, or by order or decision line 20 of the commission. The commission shall exercise its enforcement line 21 powers to ensure compliance by all load-serving entities. line 22 (f)  (1)  The commission shall require sufficient information, line 23 including, but not limited to, anticipated load, actual load, and line 24 measures undertaken by a load-serving entity to ensure resource line 25 adequacy, to be reported to enable the commission to determine line 26 compliance with the resource adequacy requirements established line 27 by the commission.
line 28 (2)  The commission shall calculate and publish annually on its line 29 internet website, in a new report or as part of another report, the line 30 percentage of each load-serving entity’s local and system resource line 31 adequacy requirements from the previous calendar year that was line 32 met with capacity from eligible renewable energy resources line 33 pursuant to the California Renewables Portfolio Standard Program line 34 (Article 16 (commencing with Section 399.11)), other zero-carbon line 35 resources, including large hydroelectric and nuclear resources, or line 36 energy storage resources. In determining the percentage of each line 37 load-serving entity’s resource adequacy requirements, the line 38 commission shall include all directly owned or contracted resources line 39 and each load-serving entity’s allocation of any centrally procured line 40 resources or allocation of resources pursuant to any other 98 — 9 — AB 1373
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line 1 mechanism that involves an assignment or allocation of resources line 2 purchased or owned by a single buyer, and shall exclude any share line 3 of a load-serving entity’s resources that were allocated to another line 4 load-serving entity.
line 5 (g)  An electrical corporation’s costs of meeting or reducing line 6 resource adequacy requirements, including, but not limited to, the line 7 costs associated with system reliability, local area reliability, and line 8 flexibility, flexible resource adequacy, renewable integration, or line 9 resource diversity portfolio requirements, that are determined to line 10 be reasonable by the commission, or are otherwise recoverable line 11 under a procurement plan approved by the commission pursuant line 12 to Section 454.5, shall be fully recoverable from those customers line 13 on whose behalf the costs are incurred, as determined by the line 14 commission, at the time the commitment to incur the cost is made, line 15 on a fully nonbypassable basis, as determined by the commission. line 16 The commission shall exclude any amounts authorized to be line 17 recovered pursuant to Section 366.2 when authorizing the amount line 18 of costs to be recovered from customers of a community choice line 19 aggregator or from customers that purchase electricity through a line 20 direct transaction pursuant to this subdivision. line 21 (h)  The commission shall determine and authorize the most line 22 efficient and equitable means for achieving all of the following:
line 23 (1)  Meeting the objectives of this section.
line 24 (2)  Ensuring that investment is made in new generating capacity. line 25 capacity, including the capacity needed to achieve the state policy line 26 specified in Section 454.53.
line 27 (3)  Ensuring that existing generating capacity that is economic line 28 is retained. retained, including the capacity needed to maintain line 29 reliability while achieving the state policy specified in Section line 30 454.53.
line 31 (4)  Ensuring that the cost of generating capacity and demand line 32 response is allocated equitably.
line 33 (5)  Ensuring that community choice aggregators can determine line 34 the generation resources used to serve their customers. line 35 (6)  Ensuring that investments are made in new and existing line 36 demand response resources that are cost effective and help to line 37 achieve electrical grid reliability and the state’s goals for reducing line 38 emissions of greenhouse gases.
line 39 (7)  Minimizing the need for backstop procurement by the line 40 Independent System Operator.
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line 1 (i)  In making the determination pursuant to subdivision (h), the line 2 commission may consider a centralized resource adequacy line 3 mechanism among other options.
line 4 (j)  The commission shall ensure appropriate valuation of both line 5 supply and load modifying demand response resources. The line 6 commission, in an existing or new proceeding, shall establish a line 7 mechanism to value load modifying demand response resources, line 8 including, but not limited to, the ability of demand response line 9 resources to help meet distribution needs and transmission system line 10 needs and to help reduce a load-serving entity’s resource adequacy line 11 obligation pursuant to this section. In determining this value, the line 12 commission shall consider how these resources further the state’s line 13 electrical grid reliability and the state’s goals for reducing line 14 emissions of greenhouse gases. The commission, Energy line 15 Commission, and Independent System Operator shall jointly ensure line 16 that changes in demand caused by load modifying demand response line 17 are expeditiously and comprehensively reflected in the Energy line 18 Commission’s Integrated Energy Policy Report forecast, forecast line 19 and in planning proceedings and associated analyses, and shall line 20 encourage reflection of these changes in demand in the operation line 21 of the grid.
line 22 (k)  For purposes of this section, “load-serving entity” means an line 23 electrical corporation, electric service provider, or community line 24 choice aggregator. “Load-serving entity” does not include any of line 25 the following:
line 26 (1)  A local publicly owned electric utility.
line 27 (2)  The State Water Resources Development System commonly line 28 known as the State Water Project.
line 29 (3)  Customer generation located on the customer’s site or line 30 providing electric service through arrangements authorized by line 31 Section 218, if the customer generation, or the load it serves, meets line 32 one of the following criteria:
line 33 (A)  It takes standby service from the electrical corporation on line 34 a commission-approved rate schedule that provides for adequate line 35 backup planning and operating reserves for the standby customer line 36 class.
line 37 (B)  It is not physically interconnected to the electrical line 38 transmission or distribution grid, so that, if the customer generation line 39 fails, backup electricity is not supplied from the electrical grid. 98 — 11 — AB 1373
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line 1 (C)  There is physical assurance that the load served by the line 2 customer generation will be curtailed concurrently and line 3 commensurately with an outage of the customer generation. line 4 SEC. 4. Section 454.51 of the Public Utilities Code is amended line 5 to read:
line 6 454.51. The commission shall do all of the following:
line 7 (a)  Identify a diverse and balanced portfolio of resources needed line 8 to ensure a reliable electricity supply that provides optimal line 9 integration of renewable energy and resource diversity in a line 10 cost-effective manner. The portfolio shall be used by the line 11 commission to establish integrated resource planning-based line 12 procurement requirements that rely upon on zero carbon-emitting line 13 resources to the maximum extent reasonable and be designed to line 14 achieve the state policy specified in Section 454.53 and any line 15 statewide greenhouse gas emissions limit established pursuant to line 16 the California Global Warming Solutions Act of 2006 (Division line 17 25.5 (commencing with Section 38500) of the Health and Safety line 18 Code) or any successor legislation.
line 19 (b)  Direct each electrical corporation to include, as part of its line 20 proposed procurement plan, a strategy for procuring best-fit and line 21 least-cost resources to satisfy the portfolio needs identified by the line 22 commission pursuant to subdivision (a).
line 23 (c)  Ensure that the net costs of any incremental renewable energy line 24 integration or diversification resources procured by an electrical line 25 corporation corporation, or the Department of Water Resources, line 26 to satisfy the need identified in subdivision (a) are allocated on a line 27 fully nonbypassable basis consistent with the treatment of costs line 28 identified in paragraph (2) of subdivision (c) of Section 365.1. line 29 (d)  Permit community choice aggregators to submit proposals line 30 for satisfying their portion of the renewable integration need line 31 identified in subdivision (a). If the commission finds this need is line 32 best met through long-term procurement commitments for line 33 resources, community choice aggregators shall also be required line 34 to make long-term commitments for resources. The commission line 35 shall approve proposals pursuant to this subdivision if it finds all line 36 of the following:
line 37 (1)  The resources proposed by a community choice aggregator line 38 will provide equivalent integration of renewable energy. 98 AB 1373 — 12 —
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line 1 (2)  The resources proposed by a community choice aggregator line 2 will promote the efficient achievement of state energy policy line 3 objectives, including reductions in greenhouse gas emissions. line 4 (3)  Bundled customers of an electrical corporation will be line 5 indifferent from the approval of the community choice aggregator line 6 proposals.
line 7 (e)  Ensure that all costs resulting from nonperformance to satisfy line 8 the need identified in subdivision (a) or (d), as applicable, shall be line 9 borne by the electrical corporation or community choice aggregator line 10 load-serving entity, as defined in Section 380, that failed to line 11 perform.
line 12 SEC. 5. Section 454.52 of the Public Utilities Code is amended line 13 to read:
line 14 454.52. (a)  (1)  Beginning in 2017, and to be updated regularly line 15 thereafter, the commission shall adopt a process for each line 16 load-serving entity, as defined in Section 380, to file an integrated line 17 resource plan, and a schedule for periodic updates to the plan, and line 18 shall ensure that load-serving entities do all of the following:
line 19 (A)  Meet the greenhouse gas emissions reduction targets line 20 established by the State Air Resources Board, in coordination with line 21 the commission and the Energy Commission, for the electricity line 22 sector and each load-serving entity that reflect the electricity line 23 sector’s percentage in achieving the economywide greenhouse gas line 24 emissions reductions pursuant to Section 38566 of the Health and line 25 Safety Code.
line 26 (B)  Procure at least 60 percent eligible renewable energy line 27 resources by December 31, 2030, consistent with the state policy line 28 specified in Section 454.53 and Article 16 (commencing with line 29 Section 399.11) of Chapter 2.3.
line 30 (C)  Enable each electrical corporation to fulfill its obligation to line 31 serve its customers at just and reasonable rates. line 32 (D)  Minimize impacts on ratepayers’ bills.
line 33 (E)  Ensure system and local reliability on both a near-term and line 34 long-term basis, including meeting the near-term and forecast line 35 long-term resource adequacy requirements of Section 380, and line 36 require sufficient, predictable resource procurement and line 37 development to avoid unplanned energy supply shortfalls by taking line 38 into account impacts due to climate change, forecasted levels of line 39 building and transportation electrification, and other factors that line 40 can result in those shortfalls.
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line 1 (F)  Comply with paragraph (1) of subdivision (b) of Section line 2 399.13.
line 3 (G)  Strengthen the diversity, sustainability, and resilience of line 4 the bulk transmission and distribution systems, and local line 5 communities.
line 6 (H)  Enhance distribution systems and demand-side energy line 7 management.
line 8 (I)  Minimize localized air pollutants and other greenhouse gas line 9 emissions, with early priority on disadvantaged communities line 10 identified pursuant to Section 39711 of the Health and Safety Code. line 11 (2)  (A)  The commission may authorize all source procurement line 12 for electrical corporations load-serving entities that includes line 13 various resource types including demand-side resources, supply line 14 side resources, and resources that may be either demand-side line 15 resources or supply side resources, taking into account the differing line 16 electrical corporations’ load-serving entities’ geographic service line 17 areas, to ensure that each load-serving entity meets the goals set line 18 forth in paragraph (1).
line 19 (B)  The commission may approve procurement of resource line 20 types that will reduce the overall emissions of greenhouse gases line 21 from the electricity sector and meet the other goals specified in line 22 paragraph (1), but due to the nature of the technology or fuel source line 23 may not compete favorably in price against other resources over line 24 the time period of the integrated resource plan. line 25 (3)  In furtherance of the requirements of paragraph (1), the line 26 commission shall consider the role of existing renewable line 27 generation, grid operational efficiencies, energy storage, and line 28 distributed energy resources, including energy efficiency, in line 29 helping to ensure each load-serving entity meets energy needs and line 30 reliability needs in hours to encompass the hour of peak demand line 31 of electricity, excluding demand met by variable renewable line 32 generation directly connected to a California balancing authority, line 33 as defined in Section 399.12, while reducing the need for new line 34 electricity generation resources and new transmission resources line 35 in achieving the state’s energy goals at the least cost to ratepayers. line 36 (4)  Upon review of the requirements of Section 454.53 and the line 37 progress towards meeting the portfolio of resources identified in line 38 subdivision (a) of Section 454.51, the commission may direct an line 39 electrical corporation, or request the Department of Water line 40 Resources, to procure diverse clean energy resources, as defined 98 AB 1373 — 14 —
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line 1 by the commission, that meet the portfolio of resources identified line 2 in subdivision (a) of Section 454.51.
line 3 (5)  If the commission requests the Department of Water line 4 Resources to procure diverse clean energy resources pursuant to line 5 paragraph (4), the commission, in consultation with the line 6 Department of Water Resources, shall develop and adopt line 7 procedures and requirements that govern procurement by, line 8 obligations on, and recovery of costs incurred by the Department line 9 of Water Resources and align with Division 29.5 (commencing line 10 with Section 80800) of the Water Code. The commission may line 11 review that procurement and, if approved, issue an order governing line 12 the recovery of the Department of Water Resources’ costs only if line 13 both of the following conditions are satisfied:
line 14 (A)  The recovery of costs to satisfy the revenue requirement of line 15 the Department of Water Resources has been found to be just and line 16 reasonable and is in the public interest.
line 17 (B)  The recovery of costs through charges on customers, line 18 including, if authorized, the issuance of bonds and the material line 19 terms of those bonds, including interest rates, rating, amortization, line 20 and maturity, does not unreasonably increase costs to customers line 21 on a net present value basis compared with the procurement of line 22 diverse clean energy resources by an electrical corporation line 23 pursuant to paragraph (4).
line 24 (b)  (1)  Each load-serving entity shall prepare and file an line 25 integrated resource plan consistent with paragraph (2) of line 26 subdivision (a) on a time schedule directed by the commission and line 27 subject to commission review.
line 28 (2)  Each electrical corporation’s plan shall follow Section 454.5. line 29 (3)  The plan of a community choice aggregator shall be line 30 submitted to its governing board for approval and provided to the line 31 commission for certification, consistent with paragraph (5) of line 32 subdivision (a) of Section 366.2, and shall achieve all of the line 33 following:
line 34 (A)  Economic, reliability, environmental, security, and other line 35 benefits and performance characteristics that are consistent with line 36 the goals set forth in paragraph (1) of subdivision (a). line 37 (B)  A diversified procurement portfolio consisting of both line 38 short-term and long-term electricity, electricity-related, and demand line 39 reduction products.
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line 1 (C)  The resource adequacy requirements established pursuant line 2 to Section 380.
line 3 (4)  The plan of an electric service provider shall achieve the line 4 goals set forth in paragraph (1) of subdivision (a) through a line 5 diversified portfolio consisting of both short-term and long-term line 6 electricity, electricity-related, and demand reduction products. line 7 (c)  To the extent that additional procurement is authorized for line 8 the electrical corporation in the integrated resource plan or the line 9 procurement process authorized pursuant to Section 454.5, the line 10 commission shall ensure that the costs are allocated in a fair and line 11 equitable manner to all customers consistent with Section 454.51, line 12 that there is no cost shifting among customers of load-serving line 13 entities, and that community choice aggregators may self-provide line 14 renewable integration resources consistent with Section 454.51. line 15 The commission may order resource procurement as a result of line 16 the integrated resource planning process and shall enforce any line 17 resource procurement requirements on a nondiscriminatory basis. line 18 (d)  To eliminate redundancy and increase efficiency, the process line 19 adopted pursuant to subdivision (a) shall incorporate, and not line 20 duplicate, any other planning processes of the commission. line 21 (e)  This section applies to an electrical cooperative, as defined line 22 in Section 2776, only if the electrical cooperative has an annual line 23 electrical demand exceeding 700 gigawatthours, as determined line 24 based on a three-year average commencing with January 1, 2013. line 25 (f)  (1)  The commission shall not include the energy, capacity, line 26 or any attribute from Diablo Canyon Unit 1 beyond November 1, line 27 2024, or Unit 2 beyond August 26, 2025, in the adopted integrated line 28 resource plan portfolios, resource stacks, or preferred system plans. line 29 (2)  The commission shall disallow a load-serving entity from line 30 including in their adopted integrated resource plan any energy, line 31 capacity, or any attribute from the Diablo Canyon Unit 1 beyond line 32 November 1, 2024, or Unit 2 beyond August 26, 2025. line 33 (g)  For a thermal powerplant that uses nuclear fission technology line 34 not constructed in the twenty-first century, all resource attributes line 35 shall be retired on January 1, 2031, and shall be reported as a line 36 separate, line item resource for purposes of complying with Section line 37 398.4.
line 38 SEC. 6. Section 80713 is added to the Water Code, to read:
line 39 80713. (a)  (1)  The Public Utilities Commission shall annually line 40 assess a capacity payment for the use of the Department of Water 98 AB 1373 — 16 —
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line 1 Resources Electricity Supply Reliability Reserve Fund established line 2 pursuant to Section 80720 by each load-serving entity that fails line 3 to meet its system resource adequacy requirements pursuant to line 4 Section 380 of the Public Utilities Code during any month in which line 5 resources procured using moneys from the Department of Water line 6 Resources Electricity Supply Reliability Reserve Fund were used line 7 to meet a reliability need. The purpose of the capacity payment is line 8 to replenish the Department of Water Resources Electricity Supply line 9 Reliability Reserve Fund. The capacity payment is not a penalty line 10 and does not prohibit the Public Utilities Commission from line 11 assessing a penalty on a load-serving entity for a failure to comply line 12 with any resource adequacy requirement.
line 13 (2)  The capacity payment shall be remitted to the Department line 14 of Water Resources Electricity Supply Reliability Reserve Fund line 15 by a load-serving entity that fails to meet its system resource line 16 adequacy requirements within 30 days of the commission notifying line 17 the load-serving entity.
line 18 (3)  Unless a different calculation methodology is specified line 19 pursuant to subdivision (b), the capacity payment for each line 20 load-serving entity shall be calculated by the Public Utilities line 21 Commission as follows:
line 22 (A)  A dollar amount equal to the per-kilowatt monthly cost of line 23 the resources procured using moneys from the Department of line 24 Water Resources Electricity Supply Reliability Reserve Fund, line 25 which shall be calculated as the annual cost of the resources line 26 procured using moneys from the Department of Water Resources line 27 Electricity Supply Reliability Reserve Fund weighted such that line 28 two-thirds of that amount reflects the costs of resources procured line 29 for summer months, which includes June to September, inclusive, line 30 and one-third of that amount reflects the costs of resources line 31 procured for other months.
line 32 (B)  The dollar amount calculated pursuant to subparagraph line 33 (A) shall be multiplied by the maximum difference between the line 34 load-serving entity’s load and the resources it procured to meet line 35 its load during the period in which resources procured using line 36 moneys from the Department of Water Resources Electricity Supply line 37 Reliability Reserve Fund were used, as determined by the line 38 commission with input from the Independent System Operator. line 39 (C)  Adjusted to reflect the load-serving entity’s estimated load line 40 minus any reductions resulting from any resources procured using 98 — 17 — AB 1373
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line 1 moneys from the Department of Water Resources Electricity Supply line 2 Reliability Reserve Fund.
line 3 (D)  Adjusted for any resources procured by electrical line 4 corporations on behalf of, and paid for by, the load-serving entity. line 5 (b)  The Public Utilities Commission, in consultation with the line 6 commission, may modify the capacity payment calculation line 7 methodology specified in paragraph (3) of subdivision (a). Any line 8 modification made by the Public Utilities Commission shall align line 9 with any modification made by the commission as authorized by line 10 subdivision (b) of Section 80714.
line 11 SEC. 7. Section 80714 is added to the Water Code, to read:
line 12 80714. (a)  (1)  The executive director of the commission shall line 13 annually assess a capacity payment for the use of the Department line 14 of Water Resources Electricity Supply Reliability Reserve Fund line 15 established pursuant to Section 80720 by each local publicly owned line 16 electric utility that fails to meet its minimum planning reserve line 17 margin established in accordance with Section 9620 of the Public line 18 Utilities Code or subdivision (b) of Section 25704.5 of the Public line 19 Resources Code, during any month in which resources procured line 20 using moneys from the Department of Water Resources Electricity line 21 Supply Reliability Reserve Fund were used to meet a reliability line 22 need.
line 23 (2)  The capacity payment shall be remitted to the Department line 24 of Water Resources Electricity Supply Reliability Reserve Fund line 25 by a local publicly owned electric utility that fails to meet its line 26 minimum planning reserve margin within 30 days of the executive line 27 director notifying the local publicly owned electric utility. line 28 (3)  Unless a different calculation methodology is specified line 29 pursuant to subdivision (b), the capacity payment for each local line 30 publicly owned electric utility shall be calculated by the line 31 commission as follows:
line 32 (A)  A dollar amount equal to the per-kilowatt monthly cost of line 33 the resources procured using moneys from the Department of line 34 Water Resources Electricity Supply Reliability Reserve Fund, line 35 which shall be calculated as the annual cost of the resources line 36 procured using moneys from the Department of Water Resources line 37 Electricity Supply Reliability Reserve Fund weighted such that line 38 two-thirds of that amount reflects the costs of resources procured line 39 for summer months, which includes June through September, 98 AB 1373 — 18 —
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line 1 inclusive, and one-third of that amount reflects the costs of line 2 resources procured for other months.
line 3 (B)  The dollar amount calculated pursuant to subparagraph line 4 (A) shall be multiplied by the maximum difference between the line 5 local publicly owned electric utility’s load and the resources it line 6 procured to meet its load during the period in which resources line 7 procured using moneys from the Department of Water Resources line 8 Electricity Supply Reliability Reserve Fund were used, as line 9 determined by the commission with input from the Independent line 10 System Operator.
line 11 (C)  Adjusted to reflect the local publicly owned electric utility’s line 12 estimated load minus any reductions resulting from any resources line 13 procured using moneys from the Department of Water Resources line 14 Electricity Supply Reliability Reserve Fund.
line 15 (b)  The commission, in consultation with the Public Utilities line 16 Commission, may modify the capacity payment calculation line 17 methodology specified in paragraph (3) of subdivision (a). Any line 18 modification made by the commission shall align with any line 19 modification made by the Public Utilities Commission as line 20 authorized by subdivision (b) of Section 80713. line 21 (c)  The commission may adopt regulations to implement this line 22 section. In order to ensure the commission implements this section line 23 coincident with the Public Utilities Commission’s implementation line 24 of Section 80713, thereby ensuring that load-serving entities and line 25 local publicly owned electric utilities are treated equally and line 26 assessed charges in a similar timeframe, the Administrative line 27 Procedure Act (Chapter 3.5 (commencing with Section 11340) of line 28 Part 1 of Division 3 of Title 2 of the Government Code) does not line 29 apply to any commission action to implement this section. line 30 SEC. 8. Section 80720 of the Water Code is amended to read:
line 31 80720. (a)  There is hereby established in the State Treasury line 32 the Department of Water Resources Electricity Supply Reliability line 33 Reserve Fund.
line 34 (b)  Notwithstanding Section 13340 of the Government Code, line 35 all moneys in the fund are continuously appropriated to the line 36 department, without regard to fiscal years, and shall be available line 37 for the purposes of Chapter 2 (commencing with Section 80710). line 38 (c)  Obligations authorized and expenses incurred by the line 39 department in administering this division shall be payable solely line 40 from the fund.
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line 1 (d)  All revenues payable to the department for activities line 2 undertaken by the department under Chapter 2 (commencing with line 3 Section 80710) or Chapter 5 (commencing with Section 80740) line 4 shall be deposited into the fund.
line 5 (e)  The fund shall be separate and distinct from any other fund line 6 and moneys administered by the department and any interest earned line 7 on the moneys in the fund shall be used solely for purposes of this line 8 division.
line 9 (f)  When fixed assets procured under the authority of this line 10 division are sold or otherwise disposed of, the revenue from the line 11 sale or disposition, including any gain or loss, measured by the line 12 difference between book value and selling price, shall be deposited line 13 into the fund and available to the department for purposes of line 14 Chapter 2 (commencing with Section 80710). Any remaining line 15 revenue from the sale or other disposition of fixed assets procured line 16 under the authority of this division shall be returned to the General line 17 Fund once all obligations of the department are satisfied after the line 18 wind down of this division and the closure of the fund. While any line 19 obligation of the department incurred under this division remains line 20 outstanding and not fully performed or discharged, the rights, line 21 powers, duties, and existence of the department shall not be line 22 diminished or impaired in any manner that will adversely affect line 23 the interests and rights of the holders of or parties to those line 24 obligations.
line 25 SEC. 9. Chapter 5 (commencing with Section 80740) is added line 26 to Division 29 of the Water Code, to read:
line 27
line 28 Chapter 5. Collection and Use of Capacity Payment line 29
line 30 80740. The department shall collect any capacity payment line 31 ordered pursuant to Section 80713 or 80714. Payments received line 32 shall be deposited into the Department of Water Resources line 33 Electricity Supply Reliability Reserve Fund established pursuant line 34 to Section 80720 and shall be used solely for the purposes of this line 35 division.
line 36 SEC. 10. Division 29.5 (commencing with Section 80800) is line 37 added to the Water Code, to read:
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line 1
line 2 DIVISION 29.5. CLEAN ENERGY CENTRAL PROCUREMENT
line 3
line 4 Chapter 1. General Provisions
line 5
line 6 80800. This division does not reduce or modify an electrical line 7 corporation’s obligation to serve.
line 8 80801. The commission shall issue orders it determines are line 9 necessary to carry out this division.
line 10 80802. (a)  The Legislature finds and declares all of the line 11 following:
line 12 (1)  California has significantly reduced the emissions of line 13 greenhouse gases from its electricity sector by fostering the line 14 development of renewable and zero-carbon energy resources line 15 through the establishment of ambitious goals and policies. These line 16 efforts have fundamentally transformed the state’s portfolio of line 17 energy resources and the day-to-day operations of the state’s line 18 electrical system.
line 19 (2)  The state has enabled the expansion of electrical retail line 20 choice for customers served in electrical corporation service line 21 territory, bringing new market entrants and innovation to line 22 California’s evolving retail electricity market. line 23 (3)  The state’s electrical system also faces the risk of increased line 24 disruption due to more frequent and intense extreme weather events line 25 fueled by a rapidly changing climate.
line 26 (4)  For California to achieve its long-term greenhouse gas line 27 emission reduction goals, while maintaining a reliable electrical line 28 system and providing customers with greater choice in electricity line 29 retail providers, the state must establish a new central procurement line 30 function within the department that enables the development of a line 31 more diverse portfolio of renewable and zero-carbon energy line 32 resources.
line 33 (b)  In enacting this division, it is the intent of the Legislature line 34 to do all of the following:
line 35 (1)  Create a central procurement function within the department line 36 that would only be exercised upon request by the commission and line 37 only if the commission finds that it is necessary to procure diverse line 38 clean energy resources beyond those procured by load-serving line 39 entities to achieve the state policy specified in Section 454.53 of line 40 the Public Utilities Code.
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line 1 (2)  If the department exercises its central procurement function, line 2 as described in paragraph (1), provide an opportunity for local line 3 publicly owned electric utilities to elect for the department to line 4 procure diverse clean energy resources on their behalf. line 5 (3)  Prohibit the department from selling any energy it acquires line 6 pursuant to this division at more than the department’s acquisition line 7 costs, including transmission, scheduling, financing, program line 8 administration, and other related costs.
line 9 (4)  Prohibit the department from pursuing procurement line 10 activities, including, if authorized, the issuance of bonds, except line 11 upon a finding from the commission that the recovery of costs line 12 through charges on customers, the issuance of bonds, and the line 13 material terms of such bonds, including interest rates, rating, line 14 amortization, and maturity, do not unreasonably increase costs line 15 to customers on a net present value basis compared with line 16 procurement of a diverse clean energy resource procured by an line 17 electrical corporation.
line 18 (5)  Require the department to prioritize investments that do not line 19 compete with the procurement of diverse clean energy resources line 20 already planned for development and disclosed by load-serving line 21 entities or local publicly owned electric utilities. line 22 80803. The development and operation of a central line 23 procurement function program as provided in this division is in line 24 all respects for the welfare and benefit of the people of the state, line 25 to protect the public peace, health, and safety, and constitutes an line 26 essential government purpose.
line 27 80804. This division shall be liberally construed in a manner line 28 so as to effectuate its purposes and objectives. line 29 80805. (a)  The powers and responsibilities of the department line 30 established pursuant to this division are separate from, and not line 31 governed by, the provisions relating to the State Water Resources line 32 Development System, including, but not limited to, those powers line 33 and responsibilities granted pursuant to Part 3 (commencing with line 34 Section 11100) of Division 6 and the California Water Resources line 35 Development Bond Act (Chapter 8 (commencing with Section line 36 12930) of Part 6 of Division 6).
line 37 (b)  The Clean Energy Central Procurement Fund established line 38 in Section 80830, and the moneys in that fund, are separate and line 39 distinct from any other fund and moneys administered by the line 40 department.
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line 1 (c)  This division does not subject the department to the line 2 jurisdictional authority of the Public Utilities Commission or line 3 expand the jurisdiction of the Public Utilities Commission, line 4 including that state water resources development system facilities line 5 subject to the California Water Resources Development Bond Act line 6 (Chapter 8 (commencing with Section 12930) of Part 6 of Division line 7 6) and the department’s other electrical generation projects or line 8 power contracts outside of those funded through the Clean Energy line 9 Central Procurement Fund, remain outside the jurisdiction of the line 10 commission.
line 11 80806. The department may adopt regulations for purposes of line 12 administering this division.
line 13
line 14 Chapter 2. Definitions
line 15
line 16 80810. For purposes of this division, the following definitions line 17 apply:
line 18 (a)  “Balancing authority area” means the collection of line 19 generation, transmission, and loads within the metered boundaries line 20 of a balancing area within California. The balancing authority line 21 maintains load resource balance within this area. line 22 (b)  “Bond” means any bond, note, or other written evidence of line 23 indebtedness issued solely for purposes of supporting the Clean line 24 Energy Central Procurement Fund and other related expenses line 25 incurred by the department pursuant to this division, or for line 26 reimbursing expenditures from the fund for those purposes, line 27 establishing or maintaining reserves in connection with a bond, line 28 costs of issuance of a bond or incidental to its payment or security, line 29 capitalized interest, or renewing or refunding any bonds. line 30 (c)  “Commission” means the Public Utilities Commission. line 31 (d)  “Electrical corporation” has the same meaning as defined line 32 in Section 218 of the Public Utilities Code.
line 33 (e)  “Energy Commission” means the State Energy Resources line 34 Conservation and Development Commission.
line 35 (f)  “Fund” means the Clean Energy Central Procurement Fund line 36 established in Section 80830.
line 37 (g)  “Independent System Operator” means the Independent line 38 System Operator described in Article 3 (commencing with Section line 39 345) of Chapter 2.3 of Part 1 of Division 1 of the Public Utilities line 40 Code.
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line 1 (h)  “Load-serving entity” has the same meaning as defined in line 2 Section 380 of the Public Utilities Code.
line 3 (i)  “Local publicly owned electric utility” has the same meaning line 4 as defined in Section 224.3 of the Public Utilities Code. line 5
line 6 Chapter 3. Department Powers
line 7
line 8 80820. (a)  In accordance with Sections 380, 454.51, 454.52, line 9 454.53, and 454.54 of the Public Utilities Code, following a line 10 determination from the commission, in consultation with the Energy line 11 Commission and the Independent System Operator, that it is line 12 necessary for the department to develop and conduct one or more line 13 competitive solicitations to procure energy, capacity, ancillary line 14 services, and all associated attributes, the department may conduct line 15 those solicitations. The purpose of these competitive solicitations line 16 is to make available to the state diverse clean energy resources line 17 that meet criteria determined by the commission, which shall line 18 include, but not be limited to, energy resources that have a first line 19 point of interconnection with the transmission grid or the line 20 distribution grid within a balancing authority area. line 21 (b)  In evaluating the bids received through the solicitation, the line 22 department shall consider all of the following:
line 23 (1)  For diverse clean energy resources dependent on the line 24 development of a project, that project’s viability, including, but line 25 not limited to, developer experience, developer financial strength line 26 and creditworthiness sufficient to eliminate financing line 27 contingencies, and the status of required permits and licenses. line 28 (2)  The ability to meet in-service dates offered during the line 29 solicitation and the ability to meet those in-service dates without line 30 escalation in cost.
line 31 (3)  The useful life of the project.
line 32 (4)  The capability to supply energy, capacity, and ancillary line 33 services at locations, times of day, and for durations that meet the line 34 state’s energy resource needs, as determined by the department line 35 and the commission.
line 36 (5)  Any other criteria determined by the commission or the line 37 department.
line 38 80821. (a)  When conducting a solicitation pursuant to Section line 39 80820, the department shall confer with the commission and other line 40 parties, including local publicly owned electric utilities 98 AB 1373 — 24 —
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line 1 participating pursuant to Section 80822, for diverse clean energy line 2 resource procurement activities of an identified scope and duration. line 3 The department shall recover costs related to conducting the line 4 requested solicitations and all supporting work. Cost recovery line 5 may be effectuated, if determined to be appropriate by the line 6 commission, through a nonbypassable charge approval process line 7 or pursuant to Section 80822 for local publicly owned electric line 8 utilities.
line 9 (b)  If cost recovery is determined through a commission line 10 proceeding, the department shall recover its costs if the commission line 11 determines those costs are just and reasonable. Those costs may line 12 include costs related to bond issuance incurred pursuant to line 13 Chapter 5 (commencing with Section 80840), costs related to line 14 contracting for diverse clean energy resources, and other costs to line 15 implement this division.
line 16 (c)  If the commission determines that a nonbypassable charge line 17 necessary to fund activities conducted by the department pursuant line 18 to this division is just and reasonable, the department shall ensure line 19 it has entered into an agreement with the commission for that line 20 nonbypassable charge before it begins to incur costs related to a line 21 specific activity under this division. If the purpose of the line 22 nonbypassable charge is to recover the department’s revenue line 23 requirement related to bond issuance debt service, the department line 24 shall ensure the agreement has the force and effect of an line 25 irrevocable financing order adopted in accordance with Article line 26 5.5 (commencing with Section 840) of Chapter 4 of Part 1 of line 27 Division 1 of the Public Utilities Code or that the commission has line 28 separately issued an irrevocable financing order related to the line 29 nonbypassable charge.
line 30 (d)  Any agreement between the department and the commission line 31 under this section shall provide for the administration of the line 32 nonbypassable charge, including both of the following line 33 requirements:
line 34 (1)  The department shall notify the commission each year of line 35 the annual collections received by the department and the amount line 36 of any excess or deficiency in collections above or below the line 37 revenue requirement. The commission shall adjust charges in the line 38 subsequent year to reflect that excess or deficiency. line 39 (2)  During any period, if the department forecasts that the line 40 revenue requirement for that period will not be met and that 98 — 25 — AB 1373
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line 1 collections will not be sufficient to fund any of the amounts line 2 specified in Section 80842 or subdivision (b) of Section 80830, the line 3 department shall notify the commission in writing and the line 4 commission shall act within 60 days of receiving that notice to line 5 increase the nonbypassable charge so that the amounts collected line 6 during that period are sufficient to meet those obligations. line 7 (e)  Any agreement between the department and the commission line 8 pursuant to this section that is solely for the purpose of imposing line 9 a nonbypassable charge to recover the department’s revenue line 10 requirement related to bond issuance debt service shall include a line 11 provision stating that the commission’s just and reasonable line 12 determination with respect to the revenue requirement is in effect line 13 for the duration of the bond term.
line 14 80822. (a)  Pursuant to Section 80820, the department may line 15 establish a schedule and mechanism for any local publicly owned line 16 electric utility to voluntarily obtain from the department energy, line 17 capacity, or ancillary services to be acquired by the department line 18 through its central procurement function on a contract-by-contract line 19 basis.
line 20 (b)  In order to voluntarily participate, a local publicly owned line 21 electric utility shall commit to the imposition of a nonbypassable line 22 charge on its ratepayers sufficient at all times to fund its line 23 participation in the program and on terms and conditions as set line 24 forth in Section 80826.
line 25 80823. At the request of the department, the commission may line 26 order an electrical corporation, or its successor in the performance line 27 of a related service, to transmit or provide for the transmission line 28 of, and distribute all electricity made available by the department, line 29 and, as agent of the department, provide billing, collection, and line 30 other related services on terms and conditions that reasonably line 31 compensate the electrical corporation for its services and line 32 adequately secure payment to the department.
line 33 80824. The commission may issue rules regulating the line 34 enforcement of the agency function pursuant Section 80823 and line 35 this division, including collection of nonbypassable charges and line 36 payment into the fund on behalf of the department. line 37 80825. (a)  If the department has executed an agreement with line 38 the commission pursuant to subdivision (c) of Section 80821, the line 39 department may recover its costs, as a revenue requirement, in line 40 the amounts and at the times necessary to enable it to comply with 98 AB 1373 — 26 —
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line 1 Section 80842, and shall advise the commission and each line 2 applicable local publicly owned electric utility, as the department line 3 determines to be appropriate and subject to the terms of the line 4 agreement.
line 5 (b)  For purposes of this division and except as otherwise line 6 provided in this section, the commission’s authority as set forth line 7 in Section 451 of the Public Utilities Code shall apply. line 8 80826. (a)  A local publicly owned electric utility that line 9 voluntarily participates in the department’s central procurement line 10 function pursuant to Section 80822 shall enter into an agreement line 11 with the department for the revenue requirement to fund its line 12 participation and that agreement shall have the force and effect line 13 of an irrevocable financing order.
line 14 (b)  The agreement shall provide for the administration of the line 15 revenue requirement, including both of the following:
line 16 (1)  A requirement that the department annually notify the local line 17 publicly owned electric utility of the annual collections received line 18 by the department with respect to the revenue requirement and the line 19 amount of any excess or deficiency in collections above or below line 20 the revenue requirement. The local publicly owned electric utility line 21 shall adjust charges in the subsequent year to reflect any such line 22 excess or deficiency.
line 23 (2)  During any revenue requirement period, a requirement that, line 24 if the department forecasts that the revenue requirement for that line 25 period will not be met and that collections will not be sufficient to line 26 fund any of the amounts described in Section 80842, the department line 27 notify the local publicly owned electric utility in writing and the line 28 local publicly owned electric utility shall act within 30 days of line 29 receiving that notice to increase the charge so that the amount line 30 collected during the period are sufficient to meet those obligations. line 31 80827. All moneys collected by load-serving entities and line 32 remitted to the department for any diverse clean energy resources line 33 acquired and sold pursuant to this division, and all moneys paid line 34 directly or indirectly to or for the account of the department for line 35 any sale, exchange, transfer, or disposition of energy acquired line 36 pursuant to this division, shall be deposited into the fund in line 37 accordance with Section 80830.
line 38 80828. The department may fix and establish the procedure line 39 and charges for the sale or other disposal of energy purchased by line 40 the department.
98 — 27 — AB 1373
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line 1 Chapter 4. Clean Energy Central Procurement Fund line 2
line 3 80830. (a)  There is hereby established in the State Treasury line 4 the Clean Energy Central Procurement Fund. Notwithstanding line 5 Section 13340 of the Government Code, all moneys in the fund are line 6 continuously appropriated, without regard to fiscal year, to the line 7 department and shall be available for purposes of this division. line 8 (b)  All revenues payable to the department under this division, line 9 including proceeds of bonds issued pursuant to Chapter 5 line 10 (commencing with Section 80840), shall be deposited into the fund. line 11 Notwithstanding any other law, interest accruing on the moneys line 12 in the fund shall be deposited into the fund and shall be used for line 13 purposes of this division.
line 14 (c)  Payments from the fund may be made only for the following line 15 purposes:
line 16 (1)  Payment of any bonds or other contractual obligations line 17 authorized by this division.
line 18 (2)  The cost of energy and transmission, scheduling, and other line 19 related expenses incurred by the department.
line 20 (3)  The expenses incurred by the department in administering line 21 this division, including costs of personnel, contracts, or line 22 arrangements to carry out the department’s duties and line 23 responsibilities pursuant to this division.
line 24 (d)  Obligations authorized pursuant to this division shall be line 25 payable solely from the fund. Neither the full faith and credit nor line 26 the taxing power of the state are, or may be, pledged for any line 27 payment under any obligation authorized by this division. line 28 (e)  While any obligations of the department incurred pursuant line 29 to this division remain outstanding and not fully performed or line 30 discharged, the rights, powers, duties, and existence of the line 31 department shall not be diminished or impaired in any manner line 32 that will adversely affect the interests and rights of the holders of, line 33 or parties to, those obligations. The department may include this line 34 pledge and undertaking of the state in the department’s obligations. line 35
line 36 Chapter 5. Bonds
line 37
line 38 80840. (a)  (1)  If the commission requests the department to line 39 engage in central procurement activities pursuant to paragraph line 40 (5) of subdivision (a) of Section 454.52 of the Public Utilities Code, 98 AB 1373 — 28 —
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line 1 due to the timing of cost recovery processes, the department may line 2 determine that it is necessary or desirable to issue bonds to support line 3 activities for the procurement of diverse clean energy resources line 4 pursuant to this division.
line 5 (2)  Upon making a determination pursuant to paragraph (1), line 6 the department may issue bonds for purposes of financing the line 7 procurement of diverse clean energy resources supporting the fund line 8 and other related expenses incurred by the department pursuant line 9 to this division, and subsequent to the department having entered line 10 into an agreement with the commission regarding a revenue line 11 requirement. Bonds shall not be issued in an amount the debt line 12 service on which, to the extent payable from the fund, is estimated line 13 by the department to exceed the amounts estimated to be available line 14 in the fund for their payment.
line 15 (b)  Before the issuance of bonds in a public offering, the line 16 department shall ensure the bonds have an investment grade rating line 17 from at least one nationally recognized investment ratings firm line 18 and the document authorizing the issuance of the bonds shall line 19 provide for repayment from pledged revenues.
line 20 (c)  The commission shall have an opportunity to review the trust line 21 agreement or other document pursuant to which the bonds are line 22 issued and revenues are pledged, and shall consult with the line 23 department regarding the trust agreement or other document, to line 24 ensure its consistency with the revenue requirement agreement line 25 between the department and commission.
line 26 (d)  In addition to any other purposes for which bonds may be line 27 issued pursuant to this division, bonds may be issued for the line 28 following purposes:
line 29 (1)  Refunding bonds to obtain a lower interest rate. line 30 (2)  Refunding bonds bearing a variable interest rate with bonds line 31 bearing interest at a fixed rate.
line 32 (3)  Refunding bonds if a nationally recognized investment line 33 ratings firm reduces or withdraws, or proposes to reduce or line 34 withdraw, the rating assigned to securities that are secured by line 35 bond insurance policies, credit, or liquidity facilities issued by the line 36 provider of a bond insurance policy, or a credit or liquidity facility line 37 securing the bonds being refunded.
line 38 (4)  Refunding bonds issued to preserve a federal income tax line 39 exemption or to qualify or maintain other federal income tax line 40 benefits.
98 — 29 — AB 1373
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line 1 80841. (a)  Whenever the director determines that the issuance line 2 of bonds is necessary or desirable to accomplish the goals set forth line 3 in this division, including financing the procurement of diverse line 4 clean energy resources, the director shall issue a written line 5 determination authorizing the issuance of bonds by the department. line 6 The department, in consultation with the Department of Finance, line 7 shall notify the Chairperson of the Joint Legislative Budget line 8 Committee and the chairpersons of the fiscal committees of each line 9 house of the Legislature of its written determination. The bonds line 10 shall be sold in the manner, and on the terms and conditions, line 11 specified in that determination, and the determination may contain line 12 or authorize any other provision, condition, or limitation not line 13 inconsistent with this division and those provisions as may be line 14 deemed reasonable and proper for the security of the bondholders. line 15 Bonds may mature at the time or times, and bear interest at the line 16 rate or rates, which may be fixed or variable and be determined line 17 by reference to an index or such other method, and may be line 18 federally tax exempt, as specified in the determination. Neither line 19 the person executing the determination to issue bonds nor any line 20 person executing bonds shall be personally liable therefor or be line 21 subject to any personal liability or accountability by reason of the line 22 issuance of the bonds.
line 23 (b)  In the discretion of the department, bonds may be secured line 24 by a trust agreement by and between the department and a trustee, line 25 which may be any trust company or bank having trust powers line 26 within or outside the state, or the Treasurer. Notwithstanding any line 27 other law, the Treasurer shall not be deemed to have a conflict of line 28 interest by reason of acting as the trustee. The department may line 29 enter into contracts or arrangements in connection with the line 30 issuance and sale of bonds, or with respect to any outstanding line 31 bonds for so long as those bonds remain outstanding, as it shall line 32 deem to be necessary or desirable for the issuance and further line 33 security of the bonds, including, but not limited to, credit line 34 enhancement agreements, dealer agreements, purchase contracts, line 35 escrow agreements, and similar arrangements.
line 36 (c)  Bonds shall be legal investments for all trust funds, the funds line 37 of all insurance companies, savings and commercial banks, trust line 38 companies, executors, administrators, trustees, and other line 39 fiduciaries, for state school funds, pension funds, and for any funds line 40 that may be invested in county, school, or municipal bonds. 98 AB 1373 — 30 —
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line 1 (d)  Notwithstanding that bonds may be payable from a special line 2 fund, the bonds shall be deemed to be negotiable instruments for line 3 all purposes.
line 4 (e)  Any bonds, and the transfer of and income derived from line 5 those bonds, shall at all times be free from taxation of every kind line 6 by the state and by the political subdivisions of the state. line 7 (f)  Bonds shall not be deemed to constitute a debt or liability line 8 of the state or of any political subdivision thereof, other than the line 9 department, or a pledge of the full faith and credit of the state or line 10 of any such political subdivision, but shall be payable solely from line 11 the revenues described in paragraph (1) of subdivision (g). All line 12 bonds shall contain a statement to the following effect: “Neither line 13 the faith and credit nor the taxing power of the State of California line 14 is pledged to the payment of the principal of or interest on this line 15 bond.” The issuance of bonds shall not directly or indirectly or line 16 contingently obligate the state or any political subdivision thereof line 17 to levy or to pledge any form of taxation whatever therefor or to line 18 make any appropriation for their payment.
line 19 (g)  (1)  The department may pledge and apply all or any part line 20 of revenues of any nature whatever accruing to the department, line 21 from orders issued, charges imposed, or contracts entered into line 22 pursuant to or in furtherance of this division, or the right to receive line 23 the same, to the payment or security of any or all of the principal line 24 of the bonds or the interest thereon, in the manner and upon terms line 25 that the department deems advisable.
line 26 (2)  (A)  It is the intent of the Legislature that any pledge of line 27 moneys, revenues, or property made by the department shall be line 28 valid and binding from the time when the pledge is made; that the line 29 moneys, revenues, or property so pledged and thereafter collected line 30 from retail end use customers, or paid directly or indirectly to or line 31 for the account of the department, is hereby made, and shall line 32 immediately be, subject to the lien of that pledge without any line 33 physical delivery thereof or further act.
line 34 (B)  It is the intent of the Legislature that the lien of any such line 35 pledge shall be valid and binding against all parties having claims line 36 of any kind in tort, contract, or otherwise against the department line 37 irrespective of whether those parties have notice thereof, and that line 38 no resolution or instrument by which the pledge or lien created line 39 pursuant to this subdivision is expressed, confirmed, or approved line 40 need be filed or recorded in order to perfect the pledge or lien. 98 — 31 — AB 1373
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line 1 (C)  It is the intent of the Legislature that this paragraph, in all line 2 respects, govern the creation, perfection, priority, and enforcement line 3 of any lien created pursuant to this division.
line 4 80842. (a)  The department shall, and in any obligation entered line 5 into pursuant to this division may covenant to, at least annually, line 6 and more frequently as required, establish and revise revenue line 7 requirements sufficient, together with any moneys deposited into line 8 the fund, to provide all of the following:
line 9 (1)  The amounts necessary to pay the principal of, and premium, line 10 if any, and interest on, all bonds as and when the same shall line 11 become due.
line 12 (2)  The amounts necessary to pay for electricity purchased by line 13 it and to deliver it to purchasers, including the cost of electricity, line 14 transmission, scheduling, and other related expenses incurred by line 15 the department, or to make payments under any other contracts, line 16 agreements, or obligations entered into by it pursuant to this line 17 division, in the amounts and at the times the same shall become line 18 due.
line 19 (3)  Reserves in amount as may be determined by the department line 20 from time to time to be necessary or desirable. line 21 (4)  The pooled money investment rate on funds advanced for line 22 electricity purchases before the receipt of payment for those line 23 purchases by the purchasing entity.
line 24 (5)  The administrative costs of the department and other state line 25 agencies, including the costs and fees for professional services, line 26 bond issuance and sale, and other miscellaneous costs, incurred line 27 in connection with the issuance of bonds or the administration of line 28 this division.
line 29 (b)  The department shall notify the commission of its revenue line 30 requirement pursuant to the agreement required pursuant to line 31 Section 80821 and that revenue requirement shall be satisfied by line 32 the recovery of its costs through a nonbypassable charge. line 33 SEC. 11. No reimbursement is required by this act pursuant line 34 to Section 6 of Article XIIIB of the California Constitution because line 35 the only costs that may be incurred by a local agency or school line 36 district will be incurred because this act creates a new crime or line 37 infraction, eliminates a crime or infraction, or changes the penalty line 38 for a crime or infraction, within the meaning of Section 17556 of line 39 the Government Code, or changes the definition of a crime within 98 AB 1373 — 32 —
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line 1 the meaning of Section 6 of Article XIII B of the California line 2 Constitution.
line 3 SECTION 1. Section 25216.7 of the Public Resources Code line 4 is amended to read:
line 5 25216.7. (a)  On or before June 30, 2024, the commission, in line 6 consultation with the Public Utilities Commission, Independent line 7 System Operator, and State Air Resources Board, shall submit to line 8 the Legislature an assessment of firm zero-carbon resources that line 9 support a clean, reliable, and resilient electrical grid in California line 10 and will achieve the policy described in Section 454.53 of the line 11 Public Utilities Code.
line 12 (b)  The assessment shall do all of the following:
line 13 (1)  Identify all available, commercially feasible and line 14 near-commercially feasible firm zero-carbon resources that could line 15 support a clean, reliable, and resilient electrical grid, and line 16 distinguish which resources are capable of addressing system line 17 reliability needs and local reliability needs, with an emphasis on line 18 reducing the emissions of greenhouse gases, toxic air contaminants, line 19 and criteria air pollutants.
line 20 (2)  Evaluate the magnitude of potential needs for and role of line 21 firm zero-carbon resources using a reasonable range of resource line 22 cost and performance assumptions that reflect emerging technology line 23 trends in order to help integrate generation from eligible renewable line 24 energy resources into the electrical grid on a daily, multiday, and line 25 seasonal basis.
line 26 (3)  Identify barriers to the development of firm zero-carbon line 27 resources and possible solutions to address those barriers, including line 28 pathways for additional procurement of those resources by line 29 load-serving entities, including joint procurements by electrical line 30 corporations, community choice aggregators, direct access line 31 customers, local publicly owned electric utilities, and other public line 32 entities, or a central procurement entity.
line 33 (4)  Recommend changes to research and development projects, line 34 demonstration projects, and energy incentives to support the line 35 contributions of firm zero-carbon resources to the near-, mid-, and line 36 long-term reliability and resiliency of California’s electrical grid, line 37 consistent with California’s goals to reduce localized air pollutants line 38 and emissions of greenhouse gases, including early priority in line 39 disadvantaged communities.
98 — 33 — AB 1373
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line 1 (5)  Evaluate the reliability of load-serving entities’ integrated line 2 resource plans under multiday extreme and atypical weather events, line 3 which shall include, at minimum, events with extended periods of line 4 low renewable energy generation and events that occur in all line 5 seasons at least as frequently as once per 10 years. line 6 (6)  Evaluate the use of long-duration and multiday energy line 7 storage to achieve the goals pursuant to this section. line 8 (c)  The assessment shall not affect the process any load-serving line 9 entity uses to develop or procure resources to serve its customers. line 10 (d)  For purposes of this section, the following definitions apply:
line 11 (1)  “Eligible renewable energy resources” has the same meaning line 12 as defined in Section 399.12 of the Public Utilities Code. line 13 (2)  “Firm zero-carbon resources” are electrical resources that line 14 can individually, or in combination, deliver zero-carbon electricity line 15 with high availability for the expected duration of multiday extreme line 16 or atypical weather events, including periods of low renewable line 17 energy generation, and facilitate integration of eligible renewable line 18 energy resources into the electrical grid and the transition to a line 19 zero-carbon electrical grid.
line 20 (3)  “Load-serving entities” has the same meaning as defined in line 21 Section 380 of the Public Utilities Code.
line 22 (e)  (1)  The assessment to be submitted pursuant to subdivision line 23 (a) shall be submitted in compliance with Section 9795 of the line 24 Government Code.
line 25 (2)  Pursuant to Section 10231.5 of the Government Code, this line 26 section is repealed on January 1, 2027.

O
98 AB 1373 — 34 —
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April 19, 2023
Assemblymember Eduardo Garcia
Chair, Assembly Utilities and Energy Committee
State Capitol, Legislative Office Building
1020 N Street, Room 408A
Sacramento, CA 95814
Re: Oppose Unless Amended position on AB 1373
Dear Chair Garcia:

The California Community Choice Association (CalCCA), representing 24 operational community choice aggregators (CCAs) and serving more than 11 million people in over 200 cities and counties throughout California, respectfully, has taken an OPPOSE, UNLESS AMENDED position on your bill, AB 1373, which seeks to establish a central procurement entity (CPE) as well as make other changes with the goal of improving energy reliability.

We applaud your commitment and leadership to improve the state’s energy security, particularly after the challenges that our extreme weather events have posed for all Californians over the last few years. Without question, extreme weather events will be our future and we must plan and execute accordingly. The other primary goal of the bill – resource diversity -- has been embraced by CCAs in their own procurement practices. In fact, CCAs were early movers on Long-Duration Storage and have procured new geothermal resources in recent years. However well intended, we believe AB 1373, as currently drafted, will create unintended market disruptions that could lead to a procurement lag and create more costs for ratepayers.

Specifically, CalCCA raises significant concerns with the following:
1) Central Procurement. CalCCA questions the need for a central procurement entity. As detailed later in our letter, we have seen no evidence to suggest that the existing load serving entities (LSEs) are incapable of procuring the necessary resources to meet the state’s energy needs. Instead, insufficient infrastructure is the number one threat to meeting the state’s clean energy goals.

However, if policy makers believe that a CPE should be established, it must be designed to prevent market disruptions and it must make protecting ratepayers from unnecessary cost increases a top priority. To accomplish these goals, the bill should establish clear criteria around the types of projects that may be procured and under what conditions.

Specifically, the CPE led procurement should be limited to the following circumstances:
a) Development and construction of the resource requires a lead time of at least five years.
b) Procurement of the resource will either accelerate needed transmission construction into a resource-rich region or accelerate further resource development by other load-serving entities where substantial regional infrastructure is required.

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VCALCCA
ADVANCING LOCAL ENERGY CHOICE cal-cco.org
c) Other means of procuring the resource or accelerating the needed transmission or infrastructure development are unavailable, would cause significant delay, or would result in higher costs to ratepayers.
d) Procurement of the resource will not interfere with publicly disclosed plans of any load-serving entity to procure resources with similar characteristics in the same region.

Sharpening the focus of central procurement in this way will better prevent market disruptions by ensuring the CPE’s activities do not interfere with other planned LSE procurement. It will also ensure the tool is directed toward bringing online the types of projects that offer the greatest value to the state: opportunities that may not yet be available to other LSEs due to infrastructure constraints or unusually high costs.

AB 1373 must also limit central procurement to DWR and not permit the investor-owned utilities (IOUs) to take on this role. IOUs now only serve 47% of the California Public Utilities Commission (CPUC) jurisdictional load, and that load is declining annually. If a resource is centrally procured to meet state climate goals, tasking only DWR with the responsibility best enables cost sharing among all customers who benefit, not just those customers in an IOU service territory.
2) Expansion of CPUC Jurisdiction Over Local Authority. AB 1373 proposes to give the CPUC expanded, ill-defined Integrated Resource Plan (IRP) jurisdiction over CCA procurement autonomy by making CCAs subject to the “same requirements… that apply to electrical corporations.” The IRP statute, Section 454.52, already applies in large measure directly to all LSEs, including CCAs. The bill’s limited scope expansion creates ambiguity and potentially overrides the right – stated multiple times in statute -- of local CCAs and the communities they serve to choose the mix of resources procured to meet the CPUC’s procurement orders. Moreover, there is no rational basis for any expansion of IRP authority over CCAs; CCAs have demonstrated their ability to meet IRP requirements, collectively meeting their 2022 new build requirements (while the IOUs fell short) and on target to meet the 2023 requirements. The bill’s expanded IRP jurisdiction will do nothing to ensure reliability or reach our clean energy goals and will only override local authority and substantially limit CCAs’ ability to keep rates low for their customers. 3) Capacity Penalty Payment for Resource Adequacy (RA) Deficiencies. The bill proposes that LSEs who are short on their year-ahead RA requirements must pay a capacity payment to the state’s Strategic Reliability Reserve (SRR) if the state needs to dip into the reserves. While penalizing LSEs for failing to adhere to RA requirements may sound good, the proposal fails to recognize that there is a shortage of RA supply in the market that will persist into 2026. Many LSEs will not be able to comply despite their best efforts and willingness to pay excessive prices for the resource. Additionally, the RA program already requires LSEs to pay a penalty so this proposal will result in customers paying twice for the same deficiency. Consequently, any new RA penalties must be supported by a discretionary CPUC-penalty waiver process to avoid heaping unnecessary penalties on customers when the RA market is insufficient.

CalCCA is concerned that the bill may be focusing on the wrong problem. LSEs are able to procure new resources when such procurement is facilitated by the necessary infrastructure.

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The problem is inhospitable infrastructure and dysfunctional processes to build the needed infrastructure.

To date, in aggregate, all load-serving entities have met their procurement requirements for new, clean, energy resources. In fact, just recently, a report showed that LSEs exceeded the Mid Term Reliability (MTR) procurement order issued by the CPUC. In fact, CCAs over-procured by over 500 MWs. Contrary to misleading statements by the CPUC in recent legislative budget subcommittee hearings where they have characterized LSEs as “struggling” to procure, procurement of new supply is not the problem.

The real problem is the lack of infrastructure such as interconnection and transmission. As an example, CCAs have recently reported that they have over 790 MW of new, clean energy resources that they are unable to connect to the grid due to interconnection delays. Further complicating matters, to meet our SB 100 goals by 2045, all LSEs must increase their annual procurement rate by 557%. If our distribution and transmission infrastructure is struggling now, California will fall well short of our clean energy goals not because procurement is “struggling” but rather because the state has not addressed our significant infrastructure needs. For these reasons, CalCCA recommends that policymakers take bold steps to address our infrastructure needs immediately otherwise we will encounter another energy crisis.

We stand ready to work with you to address our energy reliability needs and ensure we remain on track to reaching our clean energy goals. If you have any questions, please contact Sean MacNeil ([email protected] or 530-400-2496), Director of Legislative Affairs.

Sincerely,
Beth Vaughan
Executive Director, CalCCA
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Page 1 of 2 ends

Staff Report – Item 4
Item 4: Recommendation to Authorize a Request for Extension to Comply with Load Management Standards
From: Girish Balachandran, CEO
Prepared by: Adam Selvin, Director of Energy Services & Community Relations Citlalli Sandoval, Senior Regulatory Advisor
Date: 4/28/2023

RECOMMENDATION
Staff recommends that the Executive Committee recommend the Board authorize Silicon Valley Clean Energy to request an extension to comply with the California Energy Commission's (CEC) Load Management Standards.

BACKGROUND
On January 20, 2023 the Office of Administrative Law approved the CEC’s regulatory action to amend the Load Management Standards (California Code of Regulations Title 20 §§ 1621-1625). The Load Management Standards apply to Silicon Valley Clean Energy in addition to California’s investor-owned utilities, publicly-owned utilities, and community choice aggregators (CCAs) and were adopted to encourage the use of electrical energy at off-peak hours, encourage the control of daily and seasonal peak loads to improve electric system equity, efficiency and reliability, minimize or delay the need for new capacity, and reduce fossil fuel consumption and greenhouse gas emissions.

The Load Management Standards include several compliance deadlines beginning in 2023 and ending in 2027.

Typically, administrative matters such as requests for extension do not require Board of Director approval. However, the Load Management Standards state that the rate approving body of a CCA can approve a plan or revisions to a previously approved plan that delays compliance or modifies compliance with the requirements of California Code of Regulations Title 20 §§ 1623.1 (b)-(c).

California Code of Regulations Title 20 §§ 1623.1 (b)-(c) require Silicon Valley Clean Energy to:
1) Upload existing time-dependent rates into the CEC’s Market Informed Demand Automation Server (MIDAS) no later than three (3) months after April 1, 2023 (i.e., July 1, 2023)1; 2) Submit to the CEC’s Executive Director of a list of load flexibility programs deemed cost-effective no later than eighteen (18) months after April 1, 2023 (i.e., October 1, 2024); 3) Request approval from its rate approving body for at least one marginal cost-based rate within twenty-seven (27) months of April 1, 2023 (i.e., July 1, 2025); and 4) Offer to each of its electricity customers within fifty-one (51) months of April 1, 2023 (i.e., July 1, 2027) voluntary participation in either a marginal cost-based rate or a cost-effective program previously identified in the list of load flexibility programs submitted to the CEC’s Executive Director. 1 Time-dependent rates are rates that can vary depending on the time of day to encourage off-peak electricity use and reductions in peak electricity use (e.g., time-of-use, hourly, and sub-hourly rates are time-dependent rates).

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SILICON VALLEY \3/ CLEAN ENERGY
Agenda Item: 4 Agenda Date: 4/28/2023

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ANALYSIS & DISCUSSION
The amended Load Management Standards require investor-owned utilities, publicly-owned utilities, and large CCAs to populate a California-wide online database that is customer and machine accessible, the Market Informed Demand Automation Server (MIDAS), with dynamic rates.2 MIDAS is designed to provide utilities’ time-varying rates, greenhouse gas emission signals, and California Independent System Operator FlexAlerts.

By July 1, 2023, Silicon Valley Clean Energy is required to upload its time-dependent rates into MIDAS.3 Silicon Valley Clean Energy has participated and continues to participate in a CEC working group for MIDAS implementation. However, timely compliance with the July 1, 2023 upload deadline is not technologically feasible or cost-effective for Silicon Valley Clean Energy, because the MIDAS database, as well as the final protocols for the upload of Silicon Valley Clean Energy’s existing time-dependent rates to the database, have not been finalized by the CEC, and therefore Silicon Valley Clean Energy cannot cost-effectively establish the automated systems necessary to perform the upload, thereby making timely compliance technologically infeasible at this time.

CCAs and investor-owned utilities are planning to submit to the CEC a letter jointly signed by all large CCAs and investor-owned utilities requesting an extension to comply with the MIDAS upload requirement. However, there is a possibility that the CEC rejects the request and requires each CCA to individually request an extension.

As a precautionary measure, Silicon Valley Clean Energy requests that the Executive Committee recommend the Board determine in connection with its grant of extension pursuant to California Code of Regulations Title 20 § 1623.1(a)(2) that despite Silicon Valley Clean Energy’s good faith efforts to comply, requiring timely compliance with the Load Management requirements will result in extreme hardship to Silicon Valley Clean Energy.

STRATEGIC PLAN
This item relates to SVCE’s Board-adopted Strategic Plan Goal 8, “Enact and maintain competitive service offerings for SVCE customers that deliver measurable economic and environmental benefits”, Measure 3, “Provide policy support for key customer-facing L&R activities.”

ALTERNATIVE
Do not authorize a request for extension. If Silicon Valley Clean Energy is not in compliance with the Load Management Standards, then the CEC could seek injunctive relief. 2 Large CCA defined as providing in excess of 700 GWh of electricity to customers in any calendar year. 3 California Code of Regulations Title 20 § 1623.1 (c)
Item 4

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Staff Report – Item 5
Item 5: Enterprise Risk Management Framework
From: Girish Balachandran, CEO
Prepared by: Amrit Singh, CFO and Director of Administrative Services Date: 4/28/2023

RECOMMENDATION
This item is for the Executive Committee’s information and presents an Enterprise Risk Management (ERM) framework to assess the organization’s risks comprehensively. The ERM framework builds off last year’s stress test analyses, which now will be an essential component of the ERM framework.

BACKGROUND
Last year staff conducted the stress test analyses with a significant focus on drivers that impact our financial viability, primarily the market and regulatory drivers that affect our power procurement costs, revenues, and ability to remain competitive. We expanded towards making it into an enterprise risk management program by including other risks, such as those that addressed risks from threats to public services or facilities. This year staff is enhancing the risk analyses towards a more comprehensive enterprise risk management program.

ANALYSIS & DISCUSSION
ERM framework is a more comprehensive organization-wide assessment of risks that can enable us to manage risks optimally in achieving our mission.

Stress testing is an essential component of ERM. We can use the ERM framework to assess the interrelatedness of various risks or their plausible combinations to model extreme but plausible (“Black Swan”) events that can have significant adverse consequences for SVCE. Such scenarios or stress tests are essential for managing risky commodity portfolios because of the inherent weakness in standard market risk measures in assessing “black swan” events such as market disruptions caused by, for example, an economic recession.

There are three main components of SVCE’s ERM framework:

1. Risk Matrix

2. Risk Register

3. Stress Tests
Risk Matrix
SVCE will use a risk matrix to assess the likelihood (frequency of occurrence) and consequence (impact) of potential risks. The matrix will enable the organization to calibrate risks and optimally direct resources to those with the most significant impact. The risk matrix, in conjunction with the risk register, will help identify the risk tolerance or acceptable level of risk after implementing planned mitigations. For example, those with a high likelihood of occurrence and high impact require an appropriate level of risk mitigation versus those with low likelihood and low impact.

The following is the current draft version of the risk matrix that staff in the coming months will further refine and attempt to quantify the risks. The matrix helps distinguish the significance among various potential risks and enables optimal risk-based decision-making.

Item 5
Agenda Item: 5 Agenda Date: 4/28/2023

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The numbers in the parentheses are for ease of referencing a particular box (level of frequency and impact) in the matrix.

Risk Register
SVCE plans to use the risk register as a record of the organization’s identified risks. The risk register:

1. Briefly describes each risk driver or source of risk

2. Lists existing mitigation strategies and additional planned mitigations

3. Ranks or quantifies, using the risk matrix, the risks listed on the register. Risk can be ranked if no mitigation actions were taken (unmitigated risks), with current mitigations (current level of risk), and with additional planned mitigations (level of risk that is acceptable).

4. Identifies a risk owner
The following is a draft illustration of the risk register.

Insignificant Minor Moderate Major Catastrophic
Risk Easily
Mitigated
through Day-to-Day Operations
Risk is
Manageable/Low
Impact on Mission
Moderate Erosion
of
Reserves/Impact
on Mission
Significant
Erosion of
Reserves/Impact
on Mission
Risk of
Existence
Certain >90% chance High (1) High (2) Extreme (3) Extreme (4) Extreme (5) Likely 50%- 90% Chance Moderate (6) High (7) High (8) Extreme (9) Extreme (10) Moderate 10%-50% Chance Low (11) Moderate (12) High (13) Extreme (14) Extreme (15) Unlikely but Plausible 5%-10% Chance Low (16) Low (17) Moderate (18) High (19) Extreme (20) Rare <=5% Chance Low (21) Low (22) Moderate (23) High (24) High (25) Frequency/Likelihood
Impact/Consequence
Item 5
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Staff will review the risk register with the CEO’s risk oversight committee.

Stress Tests
Using the risk register, staff assesses the interrelatedness of various risks or combinations of risks that can materialize simultaneously to create plausible risk events that can have a significant adverse impact on the organization. Like last year, staff has modeled the stress test scenarios identified from the ERM framework, and the results are summarized in the next agenda item.

Next steps
Staff will use the ERM framework to complete the risk register, assess the risks using the risk matrix, work across the organization to calibrate the risks, make refinements to the matrix and overall process based on first-hand experience, and develop risk mitigation strategies for highly ranked risks to reduce them to acceptable tolerance level. In the next agenda item, Staff will present the stress analyses.

STRATEGIC PLAN
These analyses support SVCE Strategic Plan Goal 15 – “Commit to maintaining a strong financial position” and Goal 16 – “Avoid failures in the management of market risk, credit risk, liquidity risk, operational risks, and enterprise risks.”

FISCAL IMPACT
The analyses will support effective risk management strategies. Unmitigated With Current Mitigations With Additional Mitigations
1 Financial
Prices Collapse; PCIA
Increases; Revenues Decrease Amrit
Reserves to withstand the
shocks; Stress Tests, Cashflow modeling
Reassess reserve
adequacy Extreme (15) Extreme (14) High (13)
.
7 Financial
Significant Number of PPAs
Default/Delay/Renegotiate for
higher prices
Monica
Supplier & Technology Diversity;
Plan for Contingencies;
Contractual language for delay
damages and default provisions
Moderate (14) Moderate (12) Moderate (12)
13 Regulatory/Compliance POLR Proceeding - Large Tie Up of Financial Reserves Amrit Hold Adequate Reserves
Manage and shape
regulatory
proceeding
Extreme (14) High (13) Moderate (18)
26 Reputational
Ineffective or sluggish
spending of approved program
dollars
Justin
Program plans developed with
stakeholders, ongoing feedback
during design/management,
increased staff/resources, and
emphasizing larger-scale
programs.

Additional staffing,
new supporting
systems, and public
reporting on impacts.

Moderate (23) Moderate (23) Moderate (23)
.
29 Reputational
Major disruption of the
T&D/Grid operator, Grid
Reliability - affects our mission
Girish Shape Regulatory and Legislative
Initiatives Moderate (18) Moderate (18) Moderate (18)
30 Operational and
Business Continuity
Natural Disaster Recovery
(Earthquake, flooding)
- Cover key business
functions (procurement,
scheduling, collateral calls …)
Monica System backups and desk
procedures
Add'l Desk
Procedures and
Continuity Plans
Low (22) Low (22) Low (22)
.
35 Operational and
Business Continuity
Calpine system failure Adam Moderate (23) Moderate (23) Moderate (23) Proposed Stress Tests (Modeled Scenarios)
Reserves; Strong Advocacy
Additional Reserves;
Revist Hedging
Strategy
Extreme (20) High(19) Moderate (18)
Economic Recession (Price Collapse -1 percentile) Coupled with Adverse Regulatory Outcomes (POLR); Increase RA/procurement costs; MTM Losses on Investments
Draft and illustrative
Risk Matrix Placement (Impact over 5-years)
Risk ID Risk Category Risk Description Risk Owner Current Mitigations Additional Planned Mitigations Item 5

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Staff Report – Item 6
Item 6: Results of Stress Test Analyses for FY2024- FY2028 Planning Horizon From: Girish Balachandran, CEO
Prepared by: Amrit Singh, CFO and Director of Administrative Services Karthik Rajan, Senior Risk Manager
Date: 4/28/2023

RECOMMENDATION
Receive the results of the Stress Test analyses. This report provides background information that staff will use in developing recommendations to the Board for adjusting reserve levels for the next fiscal year (2023-2024) budget.

BACKGROUND
Staff conducted stress tests to assess the organization’s critical risks that can threaten its viability in carrying out its mission. The stress test scenarios, also often referred to as Black Swan events in risk terminology, are extreme but plausible events that, if occurred, could have severe adverse effects on the organization.

In constructing the stress test scenarios for 2023, the SVCE team leveraged lessons and insights from the 2022 analyses.

In 2022, the SVCE team prioritized five stress test scenarios that, based on the staff’s professional assessment, could have the most severe consequences for SVCE. Of the five scenarios, four were impacted by market price uncertainties, which included both increase and collapse of market power prices coupled with insufficient financial liquidity, load losses, and loss or delay of resources under Power Purchase Agreements.

The key finding from the 2022 stress test analyses is that the most significant financial risk facing SVCE is a collapse in energy prices. A collapse in energy prices will significantly reduce SVCE’s revenues because of higher PCIA and lower PG&E generation rates. However, this price drop will not substantially reduce SVCE’s energy purchase costs because the prices for most of the forward energy purchases are locked because of hedging over the next five years, with more hedges in the earlier years aligned with the Energy Risk Management Policy hedging targets. The hedges also include contracts for the fixed-price purchase of renewable energy. The price collapse impact overwhelms all other stress factors.

This year’s analysis, described in the next section, also models a price collapse within an economic recession scenario.

ANALYSIS & DISCUSSION
The 2023 stress scenario includes these assumptions.
1) Energy price drop to statistical one percentile level To provide customers with competitive rates, SVCE sets its generation rates such that customers receive an effective discount, currently set at four percent for 2023 and 1% after that, to comparable PG&E rates. Because CCA customers must pay PCIA charges to provide the effective discount rate Item 6
Attachment 1
Agenda Item: 6 Agenda Date: 4/28/2023

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SVCE reduces its rate by the PCIA amount. As a result, if PCIA increases and PG&E generation rate decreases, SVCE generation rates decline.

Market prices for energy are at an all-time high level. The stress test scenario assumes that market prices beginning in April 2023 and for all forward months in the five-year study period drop to the one percentile level. This result is approximately a 44% drop in prices. In comparison, during the financial crisis, commodity prices (using natural gas as a proxy) dropped by about 70% within a short period. 2) Economic recession and resulting price drops lead to insufficient financial liquidity The standard credit risk management practice, except for long-term Power Purchase Agreements (PPAs), is the requirement to post collateral, usually, cash or letters of credit, when the exposure to the counterparty reaches the negotiated credit limit. A price collapse would increase our counterparty’s credit risk or exposure to SVCE, and per the contract, when the credit limit is reached, SVCE must post the required collateral. Because of SVCE’s active management of collateral posting requirements, including placing key counterparties in a lockbox mechanism in return for not having posting requirements and long-term PPAs not being subject to this requirement, the price collapse does not have a significant impact on liquidity.

The most significant impact comes from regulatory uncertainty under potential changes to the Financial Security Requirement (FSR). Each CCA must post an FSR amount to their incumbent investor-owned utilities (IOU), PG&E for SVCE, that the utility can draw upon should the CCA fail and return its customers to the IOU. The IOUs are currently the provider of last resort (POLR). The current FSR methodology is primarily based on the difference between the IOU’s retail rates and the forecast of serving the CCA load over a 6-month period, where the FSR is adjusted every six months. Under current regulatory proceedings, certain proposals from the IOUs gaining traction at the CPUC could increase the posting requirement for SVCE to two months of the energy cost of serving the customers.

Under current market conditions, this requirement could be as high as $80 million. Because under the stress case assumption, the price collapse would reduce the cost of serving the customers, the FSR is modeled at $40 million.

In 2023, SVCE has made significant strides in an investment strategy to get better returns on the cash balance. The stress test also assessed potential losses should SVCE have to liquidate the investment portfolio to respond to the modeled scenario. The interest rate would likely fall in an economic recession, resulting in better value for the SVCE portfolio. Also, given that the holding period of these investments is less than three years, the impact of potential losses is muted. SVCE can always hold the investments to maturity and potentially avoid liquidation losses during the holding period. 3) Increased bad debt and load loss due to a recession.

Economic recession often entails contraction of load and an increase in bad debt losses. The analysis assumes a 5% load loss for 20 months of the forecast. The 5% estimate is derived from the average load loss experienced during Covid. The bad debt assumption is ~1% of the revenues.

The attachments to this report contain the summary tables with financial results under the current base case scenario and the modeled stress case scenario. The base case shows a significant reserve growth from the forecast FY2023 level of $219 million to $390 million at the end of FY 2024 and continued strong growth in margins over the next five years1. If this stress were to occur, the DCOH in 2025 would drop to only 41 days, and by FY2026, SVCE would run out of cash.

The modeled results are based on the assumptions that the current high forward prices and other modeled assumptions, especially those around PCIA and PG&E generation rates, would prevail. PCIA and PG&E generation portfolio assumptions are based on public data as best modeled by the California Community 1 SVCE’s cash balance as of Feb 28th, 2023, was at about $210 million and the corresponding days cash on hand was at 194.

Item 6
Attachment 1
Agenda Item: 6 Agenda Date: 4/28/2023

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Choice Association (CalCCA) consultant NewGen Strategies and are highly uncertain. In addition to not knowing the contents of the PCIA portfolio and PG&E’s generation portfolio, PG&E’s portfolio management strategy may change from those modeled, and the California Public Utilities Commission (CPUC) may moderate future PG&E generation rate increases. All these uncertainties make the absolute value of the results highly unreliable. Nevertheless, the relative differences between the base case and the modeled stress test scenario are highly pertinent to understanding our strategic risks. The focus of the analyses is on the delta of results between the base case and the stress test scenario.

Staff will present the results of the stress test analysis to the Finance and Administration Committee in May and then to the Board in June. Like last year, the stress test analysis, updated for market prices in alignment with those used to develop the next fiscal year’s budget, will be used to update the reserves targets. The proposed methodology for updating the reserves targets is to build reserves such that if the modeled stress scenario were to occur, reserves do not fall below the minimum reserve threshold of holding 120 Days of Cash on Hand (DCOH) over the next two fiscal years and 90 DCOH over the remaining five fiscal years.

The table below summarizes what the update would look like if we were to do so at the current prices:

Current New Targets
Minimum 120 120
Goal (Target) 285 270
Maximum (Upper Target) 490 390

STRATEGIC PLAN
The analyses support SVCE Strategic Plan Goal 15 – “Commit to maintaining a strong financial position” and Goal 16 – “Avoid failures in the management of market risk, credit risk, liquidity risk, operational risks, and enterprise risks.”

FISCAL IMPACT
The stress test analyses show that the key financial risk facing SVCE is a collapse in energy prices that can significantly reduce revenues and require a substantial draw of funds from the reserves. The best mitigation of this risk is to hold sufficient funds in reserves. Staff will use the results of these analyses to recommend reserve levels for the Board to consider in setting the Fiscal Year 2023-24 budget.

ATTACHMENT

1. Summary of Base Case Results & Stress Test Results
Item 6
Attachment 1
Agenda Item: 6 Agenda Date: 4/28/2023

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Attachment 1 – Summary of Base Case Results
Item 6
Attachment 1

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Staff Report – Item 7
Item 7: Program Snapshot: Expanding Charging Incentives to New Affordable Housing From: Girish Balachandran, CEO
Prepared by: Andrea Pizano, Board Clerk/Executive Assistant Date: 4/28/2023
This item will be addressed in the form of a presentation to the Executive Committee providing a snapshot overview of expanding charging incentives to new affordable housing.

ATTACHMENT
The presentation for this item is posted to SVCE’s website.

Item 7
SILICON VALLEY \3/ CLEAN ENERGY

Silicon Valley Clean Energy Executive CommitteeApril 28, 2023

Silicon Valley Clean Energy Executive Committee
April 28, 2023