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SB-1158 Retail electricity suppliers: emissions of greenhouse gases.(2021-2022)

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Date Published: 09/19/2022 02:00 PM
SB1158:v91#DOCUMENT

Senate Bill No. 1158
CHAPTER 367

An act to amend Section 380 of, and to add Section 398.6 to, the Public Utilities Code, relating to electricity.

[ Approved by Governor  September 16, 2022. Filed with Secretary of State  September 16, 2022. ]

LEGISLATIVE COUNSEL'S DIGEST


SB 1158, Becker. Retail electricity suppliers: emissions of greenhouse gases.
Existing law vests the Public Utilities Commission (PUC) with regulatory authority over public utilities, while local publicly owned electric utilities, as defined, are under the direction of their governing boards. Existing law requires every entity that offers an electricity product for sale to retail consumers in California to disclose its electricity sources and the associated intensity of the emissions of greenhouse gases for the previous calendar year. Existing law requires a retail supplier to disclose its electricity sources as a percentage of annual sales that is derived from specified sources of energy, including eligible renewable energy resources.
This bill would require, beginning January 1, 2028, every retail supplier to annually report specified information to the State Energy Resources Conservation and Development Commission (Energy Commission), including the retail supplier’s sources of electricity used to serve loss-adjusted load for each hour during the previous calendar year and the emissions of greenhouse gases associated with those sources of electricity, as specified. The bill would require, on or before July 1, 2024, the Energy Commission to adopt rules, through an open process, subject to public comment, and adopted by a vote of the Energy Commission, to implement these reporting requirements. The bill would require the Energy Commission to share specified information with the PUC, the State Air Resources Board, and the Independent System Operator, to the extent needed, and to annually publish on its internet website an aggregated summary of the data reported by each retail supplier. The bill would require all sellers of electricity from generation facilities or energy storage facilities, and entities allocating electricity from specified sources, to timely provide specified information to the purchaser of, or entity allocated, that electricity, as specified. The bill would require the PUC, for all load-serving entities, and the governing board, for each local publicly owned electric utility, to review the total annual emissions of greenhouse gases and the annual average greenhouse gas emissions intensity reported for each load-serving entity or local publicly owned electric utility. The bill would authorize the PUC, for all load-serving entities, and the governing board, for each local publicly owned electric utility, to assess whether those emissions of greenhouse gases, combined with the load-serving entity’s or local publicly owned electric utility’s procurement plans for subsequent years, demonstrate adequate progress toward achieving the load-serving entity’s or local publicly owned electric utility’s greenhouse gas emissions reduction targets.
Existing law requires the PUC, in consultation with the Independent System Operator, to establish resource adequacy requirements for all load-serving entities, including electrical corporations, electric service providers, and community choice aggregators, in accordance with specified objectives.
This bill would require the PUC to calculate and publish on its internet website 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, other zero-carbon resources, or energy storage resources, as specified.
This bill would incorporate additional changes to Section 380 of the Public Utilities Code proposed by SB 1432 to be operative only if this bill and SB 1432 are enacted and this bill is enacted last.
Under existing law, a violation of the Public Utilities Act or any order, decision, rule, direction, demand, or requirement of the PUC is a crime.
Because the provisions of this bill would be a part of the act and because a violation of a commission action implementing the bill’s requirements would be a crime, the bill would impose a state-mandated local program. By placing additional reporting duties upon local publicly owned electric utilities, 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 specified reasons.
Vote: MAJORITY   Appropriation: NO   Fiscal Committee: YES   Local Program: YES  

The people of the State of California do enact as follows:


SECTION 1.

 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 and needed.
(2) Establish new, or maintain existing, demand response products and tariffs that facilitate the economic 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.
(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 the renewables portfolio standard program that are applicable 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, 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 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.
(3) Ensuring that existing generating capacity that is economic is retained.
(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, 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.
(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. 1.5.

 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 and needed.
(2) Establish new, or maintain existing, demand response and distributed energy products and tariffs that facilitate the economic dispatch and use of demand response and distributed energy products that can either meet or reduce a load-serving entity’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.
(5) Maximize the ability of community choice aggregators and electric service providers to determine the resources used to serve their customers.
(6) Incorporate industry planning standards when setting compliance obligations.
(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) (1) 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 the renewables portfolio standard program that are applicable 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.
(2) The commission shall analyze, compile, and publish on its internet website an annual report on the compliance status of 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, 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 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.
(3) Ensuring that existing generating capacity that is economic is retained.
(4) Ensuring that the cost of generating capacity and demand response is allocated equitably.
(5) Ensuring that community choice aggregators and electric service providers 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, and in planning proceedings and associated analyses, and shall encourage reflection of these changes in demand in the operation of the grid.
(k) The Independent System Operator shall ensure that the cost of backstop procurement and associated greenhouse gas attributes are equitably allocated.
(l) 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.
(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. 2.

 Section 398.6 is added to the Public Utilities Code, to read:

398.6.
 (a) For purposes of this section, the following definitions apply:
(1) “Avoided greenhouse gas emissions” means greenhouse gas emissions associated with hourly purchases of electricity from specified sources that are in excess of the retail supplier’s loss-adjusted load for that hour to the extent that the excess electricity reduced the emissions of greenhouse gases associated with electricity from unspecified sources during that hour.
(2) “Electricity source type” means the fuel, source of energy, or electricity product, as described in subdivision (h) of Section 398.4.
(3) “Load-serving entity” has the same meaning as defined in Section 380.
(4) “Loss-adjusted load” means the total amount of electricity, measured at the utility-scale generation source, that a retail supplier requires in order to provide for retail sales after electrical losses in transmission and distribution.
(b) Beginning January 1, 2028, every retail supplier that offers an electricity product for sale to retail customers in the state shall annually report to the Energy Commission all of the following information:
(1) The retail supplier’s sources of electricity used to serve loss-adjusted load for each hour during the previous calendar year.
(2) To the extent feasible, the emissions of greenhouse gases associated with each of those sources of electricity. In calculating those emissions of greenhouse gases, the retail supplier shall not include or consider any avoided greenhouse gas emissions.
(3) An annual total of greenhouse gas emissions and an annual average greenhouse gas emissions intensity, calculated as the annual total greenhouse gas emissions divided by the retail supplier’s annual total loss-adjusted load.
(4) An annual total of avoided greenhouse gas emissions.
(c) On or before July 1, 2024, the Energy Commission shall adopt rules, through an open process, subject to public comment, and adopted by a vote of the Energy Commission, to implement the requirements of this section.
(d) The Energy Commission shall share the information collected pursuant to subdivision (b) with the commission, the State Air Resources Board, and the system operator, to the extent needed, for purposes of the following:
(1) Evaluating load-serving entities’ integrated resource plans pursuant to Section 454.52, as determined and deemed necessary by the Public Utilities Commission.
(2) The State Air Resources Board’s regulations for the mandatory reporting of the emissions of greenhouse gases.
(3) Estimating hourly greenhouse gas emission factors for electricity from unspecified sources, to the extent feasible.
(e) The Energy Commission shall annually publish on its internet website an aggregated summary of the data reported by each retail supplier pursuant to this section, which may include all of the following:
(1) Electricity from specified sources expressed as a percentage of annual loss-adjusted load that is derived from each electricity source type.
(2) Electricity from unspecified sources expressed as a percentage of annual loss-adjusted load.
(3) The total emissions of greenhouse gases associated with all electricity used to serve loss-adjusted load. In calculating those emissions of greenhouse gases, any avoided greenhouse gas emissions shall not be included or considered.
(4) The average greenhouse gas emissions intensity of all electricity used to serve loss-adjusted load.
(5) The total avoided greenhouse gas emissions.
(f) In order to ensure that a retail supplier can obtain the information necessary to comply with the requirements of this section and to protect the confidentiality of market sensitive data, all of the following shall be required:
(1) All sellers of electricity from generation facilities shall timely provide each purchaser of the facility’s electricity that is subject to the reporting requirement in subdivision (b) with the purchaser’s hourly share of electricity that is scheduled into a California balancing authority and the emissions of greenhouse gases associated with that electricity.
(2) All sellers of electricity from energy storage facilities shall timely provide each purchaser of the facility’s exported electricity that is subject to the reporting requirement in subdivision (b) with the purchaser’s hourly share of exported electricity and the hourly electricity consumed by the energy storage facility in prior hours sufficient to provide the exported electricity after taking into account round-trip losses within the energy storage facility. If the purchaser of the facility’s exported electricity is not responsible for providing the electricity consumed by the energy storage facility in prior hours, the seller of electricity from the energy storage facility shall also provide the purchaser with the electricity source type and the emissions of greenhouse gases associated with the electricity consumed by the energy storage facility in prior hours.
(3) An entity allocating electricity from specified sources shall timely provide each retail supplier to whom a share of the electricity is allocated with the retail supplier’s hourly share of electricity from each specified source and the emissions of greenhouse gases associated with that electricity.
(4) The recipients of hourly data pursuant to this subdivision shall maintain the confidentiality of the data received and use it solely for the purpose of meeting the requirements of this section.
(5) The recipients of hourly data pursuant to this subdivision shall share the hourly data as necessary, and under the same confidentiality requirements, with subsequent purchasers of the electricity from specified sources.
(g) (1) The commission shall review the total annual emissions of greenhouse gases and the annual average greenhouse gas emissions intensity reported for each load-serving entity pursuant to this section and may assess whether those emissions of greenhouse gases, combined with the load-serving entity’s procurement plans for subsequent years, demonstrate adequate progress toward achieving the load-serving entity’s greenhouse gas emissions targets established pursuant to Section 454.52. The commission shall provide its findings for each community choice aggregator to the community choice aggregator’s governing board.
(2) The governing board of each local publicly owned electric utility shall review the total annual emissions of greenhouse gases and the annual average greenhouse gas emissions intensity reported for each local publicly owned electric utility pursuant to this section and may assess whether those emissions of greenhouse gases, combined with the local publicly owned electric utility’s procurement plans for subsequent years, demonstrate adequate progress toward achieving the local publicly owned electric utility’s greenhouse gas emissions targets established pursuant to Section 9621. A local publicly owned electric utility may use existing board processes to facilitate this paragraph.
(h) Information submitted to the Energy Commission pursuant to this section that is a trade secret, as defined in subdivision (d) of Section 3426.1 of the Civil Code, shall not be released except in an aggregated form such that trade secrets cannot be discerned.
(i) It is the intent of the Legislature that the reporting, evaluation, and progress assessment requirements of this section shall not constitute a new electricity procurement obligation for load-serving entities or for local publicly owned electric utilities.
(j) The requirements of this section shall not apply to the following types of retail suppliers:
(1) Load-serving entities that are not subject to the requirements of Section 454.52.
(2) Local publicly owned electric utilities that are not subject to the requirements of Section 9621.
(k) In developing the rules and procedures specified in this section, the Energy Commission shall seek to minimize the reporting burden and the cost of reporting that it imposes on retail suppliers.
(l) The Energy Commission may modify or adjust the requirements of this section for any electrical corporation with 60,000 or fewer customer accounts in the state or any retail supplier with an annual electrical demand of less than 1,000 gigawatthours, if the Energy Commission finds that the costs to comply with the requirements of this section unduly burden the electrical corporation or retail supplier.
(m) The Energy Commission may delay when retail suppliers shall begin reporting pursuant to this section if the Energy Commission determines that it is infeasible or unreasonably costly for retail suppliers to obtain the necessary data or develop the necessary reporting tools within the timeframe established in subdivision (b).
(n) The Energy Commission may verify environmental and procurement claims made by retail suppliers.
(o) This section shall not apply to generators providing electric service onsite, under an over-the-fence transaction as described in Section 218, or to an affiliate or affiliates, as defined in subdivision (a) of Section 372.

SEC. 3.

 Section 1.5 of this bill incorporates amendments to Section 380 of the Public Utilities Code proposed by both this bill and Senate Bill 1432. That section of this bill shall only become operative if (1) both bills are enacted and become effective on or before January 1, 2023, (2) each bill amends Section 380 of the Public Utilities Code, and (3) this bill is enacted after Senate Bill 1432, in which case Section 1 of this bill shall not become operative.

SEC. 4.

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