Existing law vests the Public Utilities Commission with regulatory authority over public utilities, including electrical corporations. Existing law requires the commission to make various reports to the Legislature, including a report on the progress made toward modernizing the states distribution and transmission grid and the impacts of distributed energy resources on the states distribution and transmission grid, as specified. The commissions Electric Rule 21 establishes a tariff that describes the interconnection, operating, and metering requirements of generation facilities to be connected to an electrical corporations distribution system.

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

Because the provisions of this bill would be a part of the act and a violation of a commission action implementing its requirements would be a crime, the this 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 vests the Public Utilities Commission with regulatory authority over public utilities, including electrical corporations. Existing law requires the commission to make various reports to the Legislature, including a report on the progress made toward modernizing the states distribution and transmission grid and the impacts of distributed energy resources on the states distribution and transmission grid, as specified.

This bill would require the commission, on or before June 1 of each year, to submit a report to the Legislature on timelines for the interconnection of customer-sited energy generation and storage resources, as specified. The bill would require the commission to consider the negligent exceedance, as defined, of an interconnection timeline, as defined, by an electrical corporation to be a failure to comply with a rule of the commission and subject to a penalty. The bill would require an electrical corporation to provide a substantial response to any queries from an interconnection applicant related to the completeness of the application and the submission of supporting information to pending applications within 3 business days.

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

Because the provisions of this bill would be a part of the act and a violation of a commission action implementing its 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.

Date of Hearing: May 17, 2023

ASSEMBLY COMMITTEE ON APPROPRIATIONS

Chris Holden, Chair

ABPCA Bill Id:AB 643

Author:(Berman) – As Amended Ver:May 1, 2023

Urgency: No State Mandated Local Program: Yes Reimbursable: No

SUMMARY:

This bill direct the California Public Utilities Commission (CPUC), on or before March 31, 2024, to commence consideration of adopting mechanisms for distributed renewable generation interconnections to enforce timelines, reduce administrative burden and provide transparency and certainty to customers.

The bill requires, as part of its consideration, to create process improvements to, and potential timelines for, Electric Rule 21, to address the following types of delays:

1. Between submittal of an application for interconnection of a customer-sited renewable generator and the electrical corporation’s determination that the application is valid and complete.
2. Between submittal of local government inspection approval of a customer-sited renewable generator and the electrical corporation’s issuance of permission to operate the generator.
3. In the electrical corporation scheduling an inspection of a customer-sited renewable generator when electrical corporation inspection is required.

FISCAL EFFECT:

To comply with this bill, CPUC, on or before March 31, 2024, must consider the goals of the bill. The CPUC would need to start a new rulemaking or revise an existing one to consider adopting mechanisms for distributed renewable generation interconnections to enforce timelines, reduce administrative burden and provide transparency and certainty to customers. The CPUC contends this work will necessarily include holding workshops and collaborating with utilities and other stakeholders and estimates the resulting cost to BE $433,000 annually for an administrative law judge ($234,000) and one regulatory analyst ($187,000), as well as minor costs associated with workshops, site visits and training (Public Utilities Reimbursement Account.)

COMMENTS:

1. Background and Purpose. Broadly speaking, interconnection refers to establishing a physical connection between an electricity generation source and an electrical utility’s distribution grid.

Interconnections to utilities under the jurisdiction of the CPUC are governed by the CPUC’s Electric Rule 21, which the CPUC describes as:

a tariff that describes the interconnection, operating and metering requirements for certain generating and storage facilities seeking to connect to the electric distribution system. The tariff provides customers wishing to install generating or storage facilities on their premises with access to the electric grid while protecting the safety and reliability of the distribution and transmission systems at the local and system levels.

Rule 21 applies to large generation sources, as well as generally smaller distributed generation facilities, such as rooftop solar systems. The CPUC notes that Rule 21 does not apply to the interconnection of generating or storage facilities intending to participate in wholesale markets overseen by the Federal Energy Regulatory Commission (FERC).

This bill concerns interconnections governed by Rule 21, especially interconnections to establish a link between distributed generation facilities and utility distribution systems.

In 2017, to accelerate the interconnection process, and pursuant to AB 2861 (Ting), Chapter 672, Statutes of 2016, the CPUC established an expedited dispute resolution process for generating facility interconnection disputes. The CPUC has also established what it calls the “Interconnection Discussion Forum,” which the CPUC describes as “an informal venue for utilities, developers, and other stakeholders to explore a wide variety of issues related to interconnection practices and policies.”

In addition, CPUC, in Decision (D.) 20-09-035, established interconnection timelines and reporting requirements for the three large investor-owned electric utilities (Pacific Gas and Electric, Southern California Edison and San Diego Gas and Electric). The decision:

• Requires the utilities to track interconnection timelines and submit the results to the CPUC and stakeholders quarterly.
• Established a standard timeline for design and construction of interconnection-related distribution upgrades as follows: 60 business days for design and 60 business days for construction or design and construction timelines, as agreed with the customer, commencing upon payment and after the customer has done everything necessary on their end to prepare for construction.
• Required that at least 95% of net energy metering (NEM) projects larger than 30 kilowatts and non-NEM projects shall meet the established timelines within two years of the decision’s tracking requirements.
• Makes projects 30 kilowatts and smaller eligible for the interconnection fast-track process, for which the timeline to interconnect is 30 business days.

These requirements notwithstanding, CPUC reports none of the IOUs have yet satisfied the 95%-requirement.

Despite these efforts, the author contends it takes utilities far too long to interconnect distributed generation facilities to the grid, in particular, interconnection of smaller distributed generation facilities, such as rooftop solar. The author asserts this delay hinders achievement of the state’s clean energy goals and harms utility customers. According to the author:

Solar adoption is key to meeting our state’s aggressive climate goals, but far too many Californians buy and install solar panels, and then lose time and money waiting for investor-owned utilities to inspect and sign off on the setup so they can start using them.

1. Related Legislation. AB 50 (Wood) requires CPUC to determine the criteria for timely energization for electric customers. AB 50 is pending is this committee.

AB 1293 (Irwin) requires CPUC provide guidance to electrical corporations for the prioritization of projects in each electrical corporation’s distribution interconnection queue and customer service connections, including that the project is shovel-ready, as determined by the CPUC. AB 1293 is pending in this committee.

AB 1482 (Gabriel) establishes an average service energization time for electric vehicle charging infrastructure of 125 business days for publicly-owned utilities (POUs), and would require POUs to annually report certain information to the California Energy Commission regarding the service energization time for electric vehicle charging infrastructure projects. AB 1482 is pending before this committee.

Analysis Prepared by: Jay Dickenson / APPR. / (916) 319-2081

Date of Hearing: April 26, 2023

ASSEMBLY COMMITTEE ON UTILITIES AND ENERGY

Eduardo Garcia, Chair

ABPCA Bill Id:AB 643 (

Author:Berman) – As Introduced Ver:February 9, 2023

SUBJECT: Electricity: interconnection timelines: report

SUMMARY: Allows the CPUC to impose fines for electrical corporations (investor-owned utilities, IOUs) that routinely violate established interconnection timelines, and consider negligent exceedance of the timeline, as defined, as a violation of CPUC rules subject to a maximum $100,000 penalty per offense. Additionally adds new reporting requirements for interconnections of customer-sited energy generation projects.

Specifically, this bill:

1. Defines “negligent exceedance” as the exceedance of an interconnection timeline by an electrical corporation that does not result from unresponsiveness by the customer and is not justified by characteristics of a project that are uniquely time-consuming compared to typical interconnection requests.
2. Requires the CPUC to consider negligent exceedance of any step in an interconnection timeline as a violation of CPUC rules subject to a maximum $100,000 penalty per offense.
3. Requires an IOU to provide a substantial response to any questions from an interconnection applicant related to completeness of the application and the submission of supporting information to pending applications within three business days.
4. Specifies the CPUC may impose fines for routine violations of interconnection timelines.
5. Requires the CPUC to annually, by June 1, submit a report to the Legislature on timelines for the interconnection of customer-sited energy generation and storage resources. The report shall, at minimum, contain interconnection timeline compliance split between projects >30 kilowatts (kW) and projects < 30 kW; timeliness of the IOUs in completing steps not specifically identified in CPUC rules governing interconnection; the number of interconnection requests received in each of the past five years, the number withdrawn, and the number of requests granted permission to operate; a summary of challenges and past improvements in reducing interconnection timelines; and any penalties assessed for timeline violations.

EXISTING LAW:

1. Authorizes the CPUC to establish an expedited distribution grid interconnection dispute resolution process with the goal of resolving disputes over interconnection applications within the jurisdiction of the CPUC in no more than 60 days from the time the dispute is formally brought to the CPUC. (Public Utilities Code § 769.5)
2. Requires an electrical corporation to permit any new or existing customer who applies for an extension of service from that electrical corporation to install an electric extension in accordance with the regulations of the CPUC and any applicable specifications of that electrical corporation. (Public Utilities Code § 783)
3. Establishes that any public utility that violates or fails to comply with any provision of the state Constitution or any provision of any order, decision, rule, or requirement of the CPUC, is subject to a penalty of not less than five hundred dollars ($500) nor more than one hundred thousand dollars ($100,000), per offense. (Public Utilities Code § 2107)
4. Establishes guidelines for the design, cost allocation, and responsibilities of a project applicant and a utility for electric distribution line extensions necessary to furnish permanent electric service. (Electric Rule 15)
5. Establishes guidelines for the design, cost allocation, and responsibilities of a project applicant and a utility for the extension of electric service from an investor-owned utility (IOU) distribution line. (Electric Rule 16)

FISCAL EFFECT: Unknown. This bill is keyed fiscal and will be referred to the Committee on Appropriations for its review.

BACKGROUND:

IOUs and Interconnection – California’s IOUs build, own, and manage most of the transmission and distribution that serves their customers. Consequently, the IOUs play an integral role in interconnecting new generation and battery resources, which are generally owned by merchant developers. These interconnection projects are split into two queues: the distribution interconnection queue, which are operated by the individual IOUs, or the transmission interconnection queue, which is operated by the California Independent System Operator (CAISO) but also involves the utilities. Which of the two queues a project enters is determined by the desired interconnection voltage level of the project. Projects exceeding a specific voltage threshold, set by whichever IOU covers the territory that the project is sited in, are routed into the transmission queue and shepherded through the process by CAISO.^[1] Regardless of whether the resource interconnects using the CAISO’s transmission interconnection process or a utility’s distribution interconnection process, additional steps must be completed with the CAISO in order for the resource to participate in the wholesale power market.

Figure 1: The Parallel Interconnection Queues for Transmission and Distribution-level Projects.^[2]

Connecting to the Distribution Grid – Rules governing the ability of new buildings, electricity generation, and storage resources to connect to the electric distribution grid are generally determined by statute, CPUC rules, and tariffs^[3] for each of the IOUs. These service connections include:

• Interconnections, which generally refer to the interaction of physical connection of an energy generation or storage device to the electric distribution system that is either in front of the meter or behind-the-meter. Interconnection is a defined term in utility tariff rules that generally describe an electric utility’s physical connection to an external source of power. The interconnection process of generation resources is largely structured by Electric Tariff Rule 21.^[4]
• New service connections, also known as “energization,” involve extending an electricity line or expanding distribution infrastructure to service new or expanded customer load. Energizations are subject to provisions specified in Electric Tariff Rule 15 (multiple customers served by circuit) and Electric Tariff Rule 16 (one customer served by circuit).

Interconnection Tariffs for Distributed Generation – All generating facilities seeking interconnection with the distribution provider’s system shall apply to the CAISO for interconnection and be subject to CAISO tariffs except for 1) Net Energy Metering (NEM) generating facilities, and 2) generating facilities that do not export to the grid or sell any exports sent to the grid (non-export generating facilities). These two resource types are subject to CPUC jurisdiction and interconnect under Rule 21 regardless of whether they interconnect to a distribution or transmission system.^[5]

Electric Tariff Rule 21 describes the interconnection, operating, and metering requirements for generation facilities to be connected to an electrical utility’s electrical system. The tariff provides customers who would like to install generating or storage facilities on their premises with access to the electric grid while protecting the safety and reliability of the electric grid at the local and system levels. Each IOU is responsible for administration of the rule in its service territory and maintains its own version of the tariff.^[6] The vast majority of Rule 21 interconnection requests are for customer-sited generation (NEM rooftop solar) on a utility’s distribution system.

Rule 21 does not apply to the interconnection of generating or storage facilities intending to participate in wholesale markets overseen by the Federal Energy Regulatory Commission (FERC). These facilities must typically apply for interconnection under the FERC-jurisdictional Wholesale Distribution Access Tariff (WDAT), when connecting to the distribution system, or the CAISO tariff, when connecting to the transmission system. The utility WDAT governs all other exporting facilities connected to the distribution system not on a NEM tariff.

Rule 21 Lifecycle – Rule 21 contains extensive provisions governing the multiple aspects of interconnection, including procedures and timeframes for reviewing applications; fee schedules to process applications and perform impact studies; standardized application forms; technical requirements for inverters and meters; and procedures for dispute resolution, among other information. The timelines provided by Rule 21 are highly specific, as shown in Figure 2.

Figure 2: Selected Timeline Requirements in Rule 21.^[7]

While these timelines are specific and provide clear targets for the IOUs to meet, there are currently no penalties levied on the IOUs for failure to adhere to the timelines. The CPUC is capable of adopting penalties pursuant to Public Utilities Code § 2107 at any time, should they so choose.

COMMENTS:

1. Author’s Statement. According to the author, “Solar adoption is key to meeting our state’s aggressive climate goals, but far too many Californians buy and install solar panels, and then lose time and money waiting for investor-owned utilities to inspect and sign off on the setup so they can start using them. The state’s rules for interconnecting solar and storage contain many time limits for various steps in the process, but the utilities routinely fail to meet those timelines with no repercussions. The cost of customer-sited solar and storage systems is often escalated by the utilities’ inconsistent review process and long delays. This bill would clarify that the CPUC can assess financial penalties if the utilities are “negligent” in adhering to the established timelines. It is our hope that the bill does not result in ongoing penalties but rather ensures the utilities do not deprioritize staffing the teams that process interconnection applications and schedule service work.”
2. Evolutions in the NEM program. California’s NEM program started in 1997, prompted by SB 656 (Alquist, Chapter 369, Statutes of 1995). It allows customers who install eligible renewable electrical generation facilities to serve onsite energy needs and receive credits on their electric bills for surplus energy sent to the electric grid. Most customer-sited, grid-connected renewable generation in California is rooftop solar, and is interconnected through NEM tariffs. Enrollment in the first NEM program, now colloquially known as “NEM 1.0,” was phased out between 2016 and 2017.

The Legislature called for revision of NEM 1.0 per AB 327 (Perea, Chapter 611, Statutes of 2013) primarily to address cost shifting associated with the full retail credits available under NEM 1.0. The CPUC responded to AB 327 with what is commonly referred to as NEM 2.0 in 2016. Customers taking service under NEM 2.0 pay the cost to connect to the grid; take service on a “time-of-use” rate plan; and pay “non-bypassable” charges that are not offset with surplus energy credits from the solar facility. In December 2022, the CPUC issued a decision adopting “NEM 3.0” seeking to further address the cost disparity between solar generators and those not on a NEM tariff,^[8] after an earlier proposed decision^[9] to refine NEM met obstacles.

The decision adopted a new tariff, and renamed it “Net Billing Tariff” (NBT), to replace the earlier NEM tariffs. The NBT’s major difference from NEM 2.0 is that under the NBT, compensation for excess generation exported to the electric grid is applied to a customer’s bill at a rate reflecting the value of this generation to the grid. The value of the export compensation is usually lower than the retail rate, but can rise above the retail rate on late summer evenings. Customer-generators can maximize bill savings under the NBT by installing battery storage along with their generation, so they can use or export stored energy during these high-value hours. NEM 2.0 ended on April 14, 2023; now all customers seeking interconnection under a NEM tariff will be under the NBT. 

These changing tariff rules have led to a recent surge in NEM interconnection requests, with customers (and developers) seeking to receive service under the more lucrative NEM 2.0 prior to the April 14^th cut-off. Both Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) have noted increase in applicant volume over the last year, largely driven by these tariff changes. PG&E reports in typical months they have approximately 10,000 unique NEM applications, but for February 2023 those jumped to 20,000.^[10] SCE saw roughly the same volume of applications in the first two months of 2023 as they did for the entirety of 2020 (~50,000); albeit the work slowdown from the COVID-19 pandemic likely impacts this comparison.¹⁰ This large influx of new NEM applications has had an understandable impact on IOU response times, but led to increasing customer anxiety and frustration as the April deadline approached.

1. Which interconnection is included? This bill establishes penalties for violation of “interconnection timelines,” and defines such timelines as any established by the CPUC for reviewing interconnection applications. But as noted above, there are many types of interconnections: NEM systems operating under Rule 21; systems participating in the wholesale market under WDAT and seeking interconnection to the distribution grid; large generation systems participating in the wholesale market under CAISO’s tariff and seeking interconnection to the transmission grid. All of these interconnection processes are unique and have unique timelines associated with their steps. Presumably, because the definition of “interconnection timelines” is limited to those established by the CPUC, and the WDAT and CAISO interconnection processes are authorized by FERC, this bill is limited to the Rule 21 process. The author has expressed his intent that this bill is focused on Rule 21, yet this is unclear in the current language.
2. Piling on the Penalties. As noted above, this bill establishes penalties for violation of “interconnection timelines,” that may rise up to $100,000 per offense. The bill additionally authorizes the CPUC to impose fines if an IOU routinely violates timelines, also with a maximum of $100,000 per offense. As shown in Figure 2, Rule 21 has many timelines associated with its processes, with interconnection applications routinely going through 15 or more steps. This holds the possibility for a much delayed project to result in a penalty to the IOU in excess of a million dollars. Multiply that by the tens of thousands of applications an IOU receives per month, and the penalties could rapidly escalate. If timelines persist across multiple projects, the IOU could be additionally penalized under this bill for routine violations, piling on more costs. The supporters of this measure have noted their intent with the penalty structure is to motivate the IOUs to prioritize these projects, citing project delays leading to customer frustration. While the bill does acknowledge that the penalty does not apply if the delay resulted from unresponsiveness by the customer or specific characteristics of the project that are uniquely time-consuming, such exceptions fail to capture the many nuances that might lead to project delays outside the IOU’s control; principle among them the massive influx of new applications received since the CPUC issued their revised NEM decision in December 2022, as noted above.
3. Onerous Reporting. Currently, IOUs are required to track interconnection timelines and submit the results to the CPUC and stakeholders every quarter. This reporting is limited to larger NEM systems, those greater than 30kW, and represent ~1% of most IOU NEM interconnection requests.^[11] Whhile these >30kW systems are subject to the CPUC requirement that at least 95% of projects meet the Rule 21 timelines, it has proven difficult for IOUs to meet that. However, for 99% of Rule 21 requests, which are <30kW, the IOUs are able to utilize a fast-track process and have a high success rate of timely interconnection, as shown in Figures 3-5.

Figure 3: PG&E NEM 30-day Results. (“BD” = business days)^[12]

Figure 4: SCE NEM 30-day Results. (“BD” = business days)^[13]

Figure 5: SDG&E NEM 30-day Results. (“BD” = business days)^[14]

This bill adds new reporting requirements to the IOUs to include the 99% of projects (the <30kW projects) currently not subject to CPUC reporting rules. However, these projects represent upwards of two orders of magnitude more applications to be reported to the CPUC quarterly. As shown in Figures 3-5, the vast majority of these <30kW projects are interconnected within 30 days. Given these factors, the costs and work hours required by the IOUs to meet the additional reporting called for under this bill appears high, while the benefit obtained from such reporting is unclear.

1. Need for amendments. Given the identified challenges with this bill’s proposed new penalty structure and reporting guidelines, the author and committee may wish to consider amendments that strike the contents of the bill and instead direct the CPUC to examine ways to further improve the Rule 21 process and address potential delays that arise outside of the current Rule 21 timelines.
2. Related Legislation.

AB 50 (Wood) establishes interim timelines for large electrical corporations to provide customer energization following a written commitment to serve by the utility. Requires that a failure to energize customers by the date provided on a commitment to serve will entitle a customer to a utility bill credit, as specified. Requires the CPUC to determine criteria for timely service for electric customers by January 1, 2025 that may replace or revise the interim timelines. Status: set for hearing in this committee on April 26, 2023.

AB 1293 (Irwin) requires the CPUC to provide guidance to investor-owned utilities (IOUs) for the prioritization of interconnection projects, including that the project is shovel-ready, as determined by the CPUC. Status: set for hearing in this committee on April 26, 2023.

AB 1482 (Gabriel) would establish an average service energization time for electric vehicle charging infrastructure of 125 business days for publicly-owned utilities (POUs), and would require POUs to annually report certain information to the CEC regarding the service energization time for electric vehicle charging infrastructure projects. It would additionally require the CPUC and the CEC, in consultation with IOUs and POUs, to jointly host an annual public workshop to review and evaluate the information submitted and to revise, if needed, the average service energization time for EV charging infrastructure. Status: set for hearing in this committee on April 26, 2023.

SB 83 (Wiener) requires IOUs to interconnect development projects to the electrical distribution system within eight weeks for projects defined as interconnection ready. Additionally, this bill requires electrical corporations to compensate development projects for failing to meet the deadline. Status: pending hearing in the Senate Committee on Energy, Utilities, and Communications.

SB 319 (McGuire) would require the CEC, CPUC, and CAISO to jointly develop and recommend an expedited permitting roadmap that describes timeframes and milestones for a coordinated, comprehensive, and efficient permitting process for electrical transmission infrastructure. Status: pending hearing in the Senate Committee on Energy, Utilities and Communications.

SB 410 (Becker) requires the CPUC to establish a working group to improve the ability of the electric IOUs to be informed of needed distribution capacity and requires the CPUC to establish timelines for interconnection projects. Status: pending hearing in the Senate Committee on Appropriations, after passage in the Senate Committee on Energy, Utilities, and Communications on a 17-0-1 vote.

1. Prior Legislation.

AB 2861 (Ting) authorizes the CPUC to establish an expedited dispute resolution process for generating facility interconnection disputes. Status: Chapter 672, Statutes of 2016.

REGISTERED SUPPORT / OPPOSITION:

Support

1000 Grandmothers for Future Generations
350 Bay Area Action
Adt, INC.
Alameda County Democratic Party
Albany Climate Action Coalition
Aztec Solar INC.
Bioenergy Association of California
California Solar & Storage Association
California State Grange
Camptonville Community Partnership, INC
Center for Community Energy
Clean Power Campaign
Climate Action California
Climate Mobilization San Diego
Climate Reality Project, Orange County
Eco Active 101
Electrochaea Corporation
Engie
Engie North America
Environmental Working Group
Extinction Rebellion San Francisco Bay Area
Indivisible East Bay
Indivisible Green Team
Infinity Energy
Jkb Energy
Mcgee-spaulding Neighbors in Action
Morongo Basin Conservation Association
Newgen Energy
Oil & Gas Action Network
Project Development Solutions (PDS)
Récolte Energy
Resource Renewal Institute
Revel Energy
Romero Institute
San Diego Community Power
San Joaquin Valley Democratic Club
Santa Cruz Climate Action Network
Sierra Club California
Skyline Smart Energy
SolidarityINFOService
Sonoma Clean Power
Sunflower Alliance
Sunnova Energy Corporation
Sunnova Energy International, INC.
Sunpower Corporation
Sunrise Bay Area
Sunrun
Sustainable Mill Valley
Terraverde Energy
Tesla
The Climate Reality Project: Silicon Valley
Wellstone Democratic Renewal Club

Oppose

Edison International and Affiliates, Including Southern California Edison
Pacific Gas and Electric Company and Its Affiliated Entities

San Diego Gas & Electric

Analysis Prepared by: Laura Shybut / U. & E. / (916) 319-2083

1. California ISO; “​Getting started - exploring interconnection to the grid”; http://www.caiso.com/participate/Pages/ResourceInterconnectionGuide/default.aspx ↑

2. California ISO; “​Getting started - exploring interconnection to the grid”; http://www.caiso.com/participate/Pages/ResourceInterconnectionGuide/default.aspx ↑

3. Documents that specify rates, charges, rules, and conditions under which an IOU will provide service. ↑

4. CPUC; “Rule 21 Interconnection”; https://www.cpuc.ca.gov/rule21/ ↑

5. CAISO “Interconnection Basics” presentation; November 2014; http://www.caiso.com/documents/interconnectionoptionsbasics.pdf ↑

6. CPUC; “Rule 21 Interconnection”; https://www.cpuc.ca.gov/rule21/ ↑

7. Data provided by the author to committee, February 28, 2023. ↑

8. CPUC D.22-12-056, Decision Revising Net Energy Metering Tariff and Subtariffs, R. 20-08-020, December 15, 2022; https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K043/500043682.PDF ↑

9. See Decision Revising Net Energy Metering and Subtariffs, CPUC, December 13, 2021, at: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M430/K903/430903088.PDF ↑

10. IOU data requests to the committee, on March 14, 2023. ↑

11. D. 20-09-035, CPUC, Decision Adopting Recommendations from Working Groups Two, Three and Subgroup, R. 17-07-007, September 30, 2020. ↑

12. Pg. 45, Betanabhatla ,V., et al., “Rule 21 Interconnection Program Evaluation,” prepared for the CPUC by Guidehouse Inc., March 2021; https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/rule21/rule-21-interconnection-program-eval_2021.pdf ↑

13. Pg. 46, Ibid. ↑

14. Pg. 47, Ibid. ↑