July 29, 2025

Regulatory Update for July 29, 2025

(Covering Week of July 21, 2025)

Our energy regulatory team has compiled a list of state and federal energy regulatory developments to keep you up to speed on key energy regulatory matters from across the United States. Stoel’s energy regulatory team is always available to answer questions about any of these developments. Click here to meet the energy regulatory team.

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CALIFORNIA PUBLIC UTILITIES COMMISSION (CPUC or COMMISSION)[1]

Proposed Decisions and Resolutions

Rulemaking (R.) 22-07-005 (Order Instituting Rulemaking to Advance Demand Flexibility Through Electric Rates)

This decision adopts guidelines for Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E) to design demand flexibility rates and comply with the California Energy Commission’s Load Management Standards. Specifically, this decision adopts guidance for how various cost components should be incorporated into demand flexibility rate proposals to provide accurate price signals that promote economically efficient load shifting and support grid reliability. Further, this decision adopts guidance for the design of customer options that promote load shifting in response to electricity pricing while minimizing bill impacts.

R.24-01-018 (Order Instituting Rulemaking to Establish Energization Timelines)

This decision partially grants PG&E’s Motion to Revise the Energization Cost Caps adopted in Decision (D.) 24-07-008. D.24-07-008 authorized PG&E to: (1) create an Electric Capacity New Business Interim Memorandum Account (interim memorandum account) to track specific costs incurred for energizing new customers over the years 2024, 2025, and 2026 up to annual caps, and (2) recover costs tracked in the account for completed energization projects in amounts determined through the Annual Electric True-Up (AET) process on an interim basis pending reasonableness review by the Commission. In its motion, PG&E seeks to increase the Commission-authorized capital cost caps established in D.24-07-008 for the years 2025 and 2026. PG&E also seeks authorization to use these capital cost caps across 2025 and 2026 and requests that the Commission eliminate the secondary revenue requirement caps for 2024, 2025, and 2026. Specifically, PG&E’s motion requests that the Commission: (1) Increase the 2025 capital costs cap from $618 million to $2.115 billion; (2) Increase the 2026 capital costs cap from $669 million to $2.302 billion; (3) Authorize the ability to spend authorized amounts across 2025 and 2026; and (4) Eliminate the secondary revenue requirement caps for 2024-2026. This decision denies the amounts requested by PG&E for 2025 and 2026 cap increases and grants lower amounts. PG&E’s capital cost caps are increased by $1,367.9 for 2025 and $1,015.7 for 2026. Accordingly, the new interim memorandum account capital cost caps are $1,985.9 for 2025 and $1,684.7 for 2026. This decision approves PG&E’s request for inter-year flexibility between the 2025 and 2026 capital expenditure caps. Additionally, this decision grants the request to eliminate the secondary annual revenue requirement caps. The annual revenue requirement additions will continue to be calculated through the AET process based on costs of projects placed in service each year and subject to claw back after reasonableness review in PG&E’s General Rate Case.

Application (A.) 23-05-010 (SCE Test Year 2025 General Rate Case)

This decision approves a test year base revenue requirement of $9.756 billion for SCE. The adopted amount is a 13.68 percent increase over SCE’s current authorized revenue requirement compared to SCE’s requested 22.15 percent increase. The decision also authorizes post-test year revenue requirement adjustments of $453 million for 2026 (a 4.64 percent increase), $411 million for 2027 (a 4.03 percent increase), and $374 million for 2028 (a 3.52 percent increase), along with the adoption of a post-test year ratemaking mechanism. The decision directs SCE to implement the 2025 test year revenue requirement in rates beginning October 1, 2025, or as soon thereafter as it may be affected. Given the timing of this implementation, the decision specifies that the incremental revenue increase that has accrued from January 1, 2025 through September 30, 2025 will be amortized over a 24-month period.

Voting Meeting

The CPUC held a voting meeting in San Francisco, California on July 24, 2025 at 11:00 a.m.  The following are results for energy-related items on the agenda:

Item 3. Application (A.) 23-11-003 (Southern California Gas Company Cost Recovery for Catastrophic Events and COVID-19 Protections)

This decision authorizes partial recovery of costs recorded in Southern California Gas Company’s (SoCalGas) Catastrophic Event Memorandum Account (CEMA) and COVID-19 Pandemic Protections Memorandum Account (CPPMA).  The total capital expenditure/operations and maintenance costs authorized for recovery is $19,231,206, and the requested amount was $58,396,224.  Most of the disallowances are due to understatement of avoided costs in CEMA Subaccount F, which covers certain costs associated with the COVID-19 pandemic.  This decision also authorizes recovery of $2.068 million in waived charges and $297,000 in interest expense associated with the CPPMA.  Authorized costs will be recovered from customer classes using the Equal Cents Per Therm methodology on a 12-month schedule.  Signed, D.25-07-009.

Item 4. Resolution (Res) E-5398 (PacifiCorp Cap-and-Trade Program)

This Resolution directs PacifiCorp to remove costs for compliance with the Washington Cap-and-Invest Program from California rates from Advice Letter (AL) 751-E.  The Commission finds that California PacifiCorp ratepayers would face additional costs if rates include costs from both the California Cap-and-Trade Program and the Washington Cap-and-Invest Program for the same emissions.  The Resolution finds that this issue should be addressed once the state agencies responsible for each program finalize an agreement to harmonize the two systems.  The respective state agencies responsible for these programs, the California Air Resources Board and the Washington Department of Ecology, are currently considering an agreement that would link their carbon markets and determine a unified compliance obligation for utilities, such as PacifiCorp, that operate under both systems.  Lastly, the Commission directs PacifiCorp to determine Washington Cap-and-Invest Program costs already collected or costs owed from California ratepayers in either the 2025 or the 2026 PacifiCorp Energy Cost Adjustment Clause Application.  Held to August 14, 2025.

Item 5. Res E-5367 (PG&E and SCE DAC-GT Cost Containment Cap Proposal)

This Resolution approves, with modifications, PG&E AL 7363-E-A and SCE AL 5362-E-A to update the cost containment cap for the Disadvantaged Communities Green Tariff (DAC-GT) program, pursuant to Decision (D.) 24-05-065.  Approved.

Item 6. Res E-5400 (2024-2027 Energy Efficiency Portfolio Business Plans for Northern California Rural Regional Energy Network and Central California Rural Regional Energy Network)

This Resolution approves the revised 2024-27 Energy Efficiency Portfolio Business Plan for Northern California Rural Regional Energy Network and the revised 2024-27 Energy Efficiency Portfolio Business Plan for Central California Rural Regional Energy Network. The cost is $60,029,938 to PG&E customers, $7,267,800 to SCE customers, and $2,180,340 to SoCalGas customers for a four-year period.   Held to August 14, 2025.

Item 18. Res G-3610 (SoCalGas’s Recovery of the Distribution Integrity Management Program Balancing Account for September 1, 2019 to January 1, 2023)

SoCalGas filed AL 6224-G requesting recovery of $81.4 million in undercollected revenue requirement for actual operations and maintenance and capital expenditures recorded in the DIMP Balancing Account (DIMPBA) through January 31, 2023. SoCalGas’s request to recover the undercollection recorded in its DIMPBA for September 1, 2019 to January 31, 2023 is approved. The DIMPBA amount will be amortized via the allocation methodology described in the decision from the most recent Triennial Cost Allocation Proceeding (A.22-09-015).  Approved.

Item 19. Res E-5386 (Shell Energy North America, L.P. Procurement Obligations)

This Resolution grants Shell Energy’s January, February, and March 2020 month-ahead local waiver requests in ALs 21-E, 22-E, and 24-E due to the significant delays in issuing the associated non-standard disposition letters denying them. Shell Energy filed the January, February, and March 2020 month-ahead local waiver ALs in 2019 and 2020. The Energy Division disposed of them in November 2024, which is almost five years after the initial filings.  Approved.

Item 25. Res E-5403 (Amendment to PG&E’s Contract with Energy Vault for Development of Clean Substation Microgrid Project)

This Resolution approves PG&E AL 7552-E without modification. In D.21-01-018 and Res E-5261, the Commission directed PG&E to develop a Clean Substation Microgrid (CSM) pilot project to mitigate Public Safety Power Shutoff events. PG&E selected the Calistoga substation for this project, entering into a contract with Energy Vault to develop a hybrid battery energy storage and hydrogen fuel cell microgrid to provide 48 hours of backup power. Through AL 7552-E, PG&E requests Commission approval to amend the contract with Energy Vault to (1) extend the project delivery milestones to reflect updated construction schedules and (2) clarify that Energy Vault may operate the microgrid in “Blue Sky” (non-islanded) mode during normal grid conditions, so long as such operations do not interfere with backup service obligations. This Resolution finds that the clarification is consistent with the original intent and context of the CSM pilot as set forth in D.21-01-018 and Res E-5261. Blue Sky operations were anticipated and encouraged as a way to better utilize project resources without introducing new ratepayer costs. This Resolution finds that PG&E’s proposed amendments are reasonable, do not introduce new ratepayer risks, and are supportive of broader Commission goals for clean energy and resiliency.  Approved.

Item 26. A.23-05-012 et al. (Large Electric Investor-Owned Utilities’ Energy Resource Recovery Account Applications)

This decision adopts the definition of fixed generation costs as “costs that do not change based on the amount of electricity customers use or the amount of operating time associated with the electricity generation.” This decision applies to PG&E, SCE, and SDG&E. The definition adopted in this proceeding will be used when evaluating each large electric utility’s annual Energy Resource Recovery Account (ERRA) applications after the issuance of this decision. Each Investor-Owned Utility’s (IOU) ERRA filing, in part, seeks Commission review of a balancing account (or accounts) that tracks and allows utilities to seek recovery of costs associated with long-term electric generation contracts the utilities entered before some portion of their customers switched to other load serving entities. Other issues related to the common costs addressed in the large electric utilities’ ERRA applications are not addressed in this decision.  Signed, D.25-07-014.

Item 27. Res G-3605 (SoCalGas’s 2024 Compliance Plan, Forecasts, and Caps for Its Natural Gas Leak Abatement Program)

This Resolution approves in part and denies in part SoCalGas’s 2024 Natural Gas Leak Abatement Compliance Plan and the ratemaking forecasts as presented in AL 6277-G-B. SoCalGas requested a forecasted total revenue requirement of $483.12 million. This Resolution approves $102 million for Blowdown Reduction Activities, as it is the sole cost-effective measure in the program. All other costs for Best Practices and Research Development & Demonstration are denied. An additional $4.245 million for SoCalGas’s Natural Gas Leak Abatement Program Administration is authorized for recording in the Natural Gas Leak Abatement Program Memorandum Account for potential recovery in a future general rate case or other proceeding, where it will be subject to reasonableness review. The Resolution approves $78.8 million for ongoing capital undercollections from previously approved Compliance Plans.  Held to August 14, 2025.

Item 29. Rulemaking (R.) 24-09-012 (Gas Utilities Memorandum Accounts to Record Expenses)

This decision permits each gas utility subject to the Assigned Commissioner’s Ruling Issuing Senate Bill 1221 Mapping Directions to Utilities, filed on April 18, 2025, to establish a memorandum account to record expenses related to complying with mapping activities per Public Utilities Code section 661. The gas utility may record such expenses in its memorandum account effective April 21, 2025. Each gas utility may record expenses in its respective memorandum account until January 1 of the Test Year of its next general rate case upon which time recording in the memorandum account must cease and ongoing expenses related to mapping activities under Section 661 must be covered in its new general rate case. The reasonableness and recovery of the expenses recorded in such memorandum accounts will not be reviewed in the proceeding, but may be addressed in each utility’s next general rate case.  Signed, D.25-07-016.

Item 52. A.24-11-007 (Motion for Interim Implementation of Electric Rule No. 30)

This decision partly grants PG&E’s January 24, 2025 motion for interim implementation of Electric Rule 30 (Motion). This decision allows for interim implementation for transmission-level customers who provide advance or actual cost payments and voluntarily prefund up to 100% of specific transmission network upgrades. The decision requires new transmission-level customers seeking retail services to be responsible for the initial costs of all transmission facilities, rather than those costs being borne by ratepayers. The Motion is partly denied for the interim implementation period regarding any refunds for advances, actual cost payments, or contributions, as well as associated accrued interest. These matters are deferred to the final decision of the proceeding, at which point the Commission will examine cost allocation and causation in light of the entire record. Similarly, the decision finds that repayments of pre-funded loans are also denied during this interim period, and their full repayment is not guaranteed. The specific cost causation and allocation mechanisms for these pre-funded loans will be decided in the final decision of this proceeding. Therefore, no rate recovery is authorized as part of this decision.  Signed, D.25-07-039.

Upcoming Events

Workshop on Slice of Day (R.23-10-011)

On Wednesday, July 30, 2025, Energy Division staff will host a workshop in the RA proceeding to review recent implementation changes, provide updated guidance on the Slice of Day compliance template, and address any related questions in advance of the 2026 RA Compliance Year.  The workshop will be held at 1:00 p.m. via Webex.  Access details are available here.

Workshop on Customer-Generated Renewables for Priority Communities (R.25-01-005)

On August 20, 2025, beginning at 9:00 a.m., the Commission will host an in-person workshop at the Granlibakken Tahoe Resort to discuss issues in the Customer-Generated Renewables proceeding. Specifically, the workshop is designed to provide guidance for small multi-jurisdictional utilities (Bear Valley, Liberty Utilities, and PacifiCorp) regarding customer generation tariffs and consumer protections.  Additional information and attendance details are available here.

CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO)

Stakeholder Initiatives: Upcoming Meetings and Deadlines

CPUC Annual Resource Adequacy Subpoena

The CPUC served its annual Resource Adequacy subpoena on CAISO on July 17, 2025. The CPUC is requesting data from CAISO in 31 broad categories. The due date for any objections to the production of responsive information is August 11, 2025 at 12:00 p.m.  Further information is available here.

2026 Net Qualifying Capacity Values for Resource Adequacy Resources

CAISO has posted the preliminary 2026 Resource Adequacy Net Qualifying Capacity (NQC) list. Scheduling coordinators are requested to review their information and submit comments by August 4, 2025 for NQC. Further information is available here.

2026 Import Capability Assignment

CAISO has posted the CAISO Maximum Resource Adequacy Import Capability for Year 2026 document, as a first step to the 2026 import capability assignment process. Further information is available here.

2025 Intra-Cluster Reliability Network Upgrade Prioritization

CAISO has posted its 2025 Intra-Cluster Reliability Network Upgrade Prioritization Study Plan and Methodology document, and a list of Interconnection Customer projects with qualifying Reliability Network Upgrades where available capacity to interconnect earlier may exist. Eligible interconnection customers will receive an email with application instructions. Further information is available here.

Transmission Development Forum

CAISO, in conjunction with the CPUC and participating transmission owners, will hold its biannual stakeholder call on July 30, 2025 to provide status updates on the transmission planning process and network upgrades identified in the generation interconnection process. Written comments on the stakeholder call discussion are due August 13, 2025.  Further information is available here.

CALIFORNIA ENERGY COMMISSION (CEC)

2025 Integrated Energy Policy Report (IEPR)

The CEC has released the 2025 IEPR workshop schedule and opened a new proceeding number (25-IEPR-01) for the 2025 IEPR.  Workshop topics and dates included in the notice are below (note: the workshop schedule is subject to change and the current schedule was released on July 2, 2025).  Upcoming workshops and recent changes to the workshop schedule are reflected below:

On July 22, 2025, the CEC released a Revised Scoping Order for the 2025 IEPR, which updates the original Scoping Order posted in March 2025.

Assembly Bill (AB) 3 California Offshore Wind Advancement Act

On June 18, 2025, CEC staff hosted a remote access workshop to present CEC staff’s proposed scope and strategy for developing the reports required by AB 3, and to receive public comment on staff’s proposals.  Staff’s Scoping Document and Literature Assessment, as well as all related workshop items, can be accessed here.  Under AB 3, the CEC is required to prepare and submit reports to the Governor and Legislature after consulting with various state agencies as follows:

  • Report 1 is a second-phase plan for seaport readiness due by December 31, 2026 (Pub. Resources Code, § 25991.8).
  • Report 2 is a feasibility study of achieving 50% and 65% in-state assembly and manufacturing of offshore wind energy projects due by December 31, 2027 ( § 25991.9).

The CEC issued a 30-day extension to the original July 18, 2025 comment deadline.  Written comments on the Scoping Document and the general workshop topics are now due to Docket No. 25-AB-03 by 5:00 p.m. on August 18, 2025.  Instructions for submitting written comments are also available here.

Electric Program Investment Charge (EPIC)

The CEC has opened registration for the 2025 EPIC Symposium, which will be held on October 7, 2025, at the California Natural Resources Agency in Sacramento.  The EPIC symposium is held in collaboration with the state’s three largest investor-owned utilities, and it convenes clean energy leaders, policy makers, researchers, entrepreneurs, and other stakeholders to discuss the latest innovations driven by EPIC. In-person attendance is limited due to venue capacity, so early registration is encouraged.  Additional information and the registration link are available here.

Electric Vehicle (EV) Charger Reliability

On June 27, 2025, the CEC issued a notice of proposed rulemaking to establish regulations for EV charger recordkeeping and reporting, reliability, and data sharing.  These regulations would apply to EV charging ports installed in California, for purposes of tracking the reliability of publicly or ratepayer-funded fast-charging ports and to set a 97% uptime standard.  The proposed express terms are available here and a CEC staff report on the proposed regulations is available here.

The CEC will host a public hearing on the proposed regulations on Wednesday, August 13, 2025 at 10:00 a.m.  The public hearing can be attended either in person (715 P Street, Sacramento, California 95814) or remotely via Zoom. Additional information is available here.

Workshop on EV Load Modeling for Publicly Owned Utilities

The CEC announced it will host a workshop on August 7, 2025 from 10:30 a.m. to 12:00 p.m. to showcase an EV charging load estimation modeling framework and toolset.  This toolset is being developed in partnership with the Pacific Northwest National Laboratory (PNNL).  During the workshop, CEC and PNNL staff will present technical details of the model’s methodology and demo a prototype version of an interactive web tool they are developing for use by publicly owned utility (POU) grid planning staff. CEC staff will also discuss how PNNL’s work is connected to the Electric Vehicle Service Equipment Deployment and Grid Evaluation (EDGE) mapping and visualization tool (EDGE tool). This workshop is designed specifically for POU distribution planning staff and will include a request for feedback and assistance.  Additional information and attendance information is available here.

CEC Business Meetings

The next CEC Business Meeting is scheduled for August 13, 2025. 

CALIFORNIA AIR RESOURCES BOARD (CARB)

Meetings and Workshops

CARB and other state regulatory agencies will hold a series of dialogue sessions meant to generate public discussion around proposed measures to support increased zero-emission vehicle adoption in California. Governor Gavin Newsom signed an executive order on June 12, 2025, which directed CARB, the CEC, the Governor’s Office of Business and Economic Development, the California State Transportation Agency, and the Department of Consumer Affairs to assess additional actions to spur light-, medium-, and heavy-duty zero-emission vehicle adoption in California, and to deliver formal recommendations for additional actions to the governor in August. The agencies are planning to host in-person sessions during business hours and one evening session online:

Long Beach:

July 31, 1:00 p.m.-5:00 p.m.
Civic Center Chambers 
411 W. Ocean Boulevard

CARB hosts a series of monthly evening community meetings on the third Tuesday of most months. The purpose of these meetings is to host focused discussions on CARB’s Clean Transportation Incentives Funding Plan (Funding Plan) development process. The Funding Plan explains how CARB will spend funds on projects related to zero-emission vehicles (ZEV) and zero-emission equipment to help improve air quality and reduce the impacts of climate change. During this month’s meeting, CARB staff will give a summary of four recent daytime meetings focusing on developing the Funding Plan for Fiscal Year 2025-26. The first presentation will cover two related workgroup meetings on Individual (Light-Duty Vehicle Purchase) and Community Mobility (Clean Mobility) Incentives and Long-Term Plan for these Individual and Community Mobility options (meetings #1 and #2, held July 10, 2025 and July 31, 2025). The second presentation will cover a workgroup meeting on the Clean Truck and Bus Voucher Incentive Project (HVIP), Clean Off-Road Equipment Voucher Incentive Project (CORE), Innovative Small e-Fleet Pilot Project (ISEF), and Long-Term Heavy-Duty Investment Strategy (held July 22, 2025). The third presentation will cover the workshop on Funding Plan Draft Allocations and Policy Changes – Clean Transportation Incentives (held August 14, 2025).

Amendments to Clean Trucks Standards

CARB approved amendments to the state’s Advanced Clean Truck (ACT) and Zero-Emission Powertrain (ZEP) Certification standards. The amendments, which CARB states constitute minor changes with no significant cost or emissions impact, were developed in response to stakeholder comments and include:  

  • Adding a “pooling” option for manufacturers to transfer surplus ZEV and near-zero-emission vehicle (NZEV) credits generated between states that adopted the ACT regulation.  
  • Permitting manufacturers to offset a portion of deficits generated in the Class 7-8 tractor group with Class 2b-3 or Class 4-8 group ZEV credits for each model year, allowing manufacturers more flexibility and to account for fluctuations in ZEV and NZEV sales across states and vehicle classes. 
  • Adjusting the minimum all-electric range requirement for NZEV in later years.  
  • Providing manufacturers increased flexibility on the order in which they retire credits.   
  • Modifying the communication protocols of the ZEV connector criteria for certifying zero-emission powertrains. 

MINNESOTA PUBLIC UTILITIES COMMISSION (MPUC)

At its July 31, 2025 weekly agenda meeting, the MPUC will consider: (1) whether to grant the requests to reconsider its June 11, 2025 Order Modifying and Adopting Administrative Law Judge Report, Granting Certificate of Need, and Issuing Route Permit for the Minnesota Energy Connection Project (Docket Nos. E002/CN-22-131; E002/TL-22-132); (2) adoption of the ALJ findings and recommendation regarding, and whether to grant, the site permit application for the Birch Coulee Solar Project (Docket No. IP7119/GS-23-477); (3) approval of a one-time exception to CIAC provisions in Xcel’s Minnesota Electric Rate Book to cover the required service and meter socket upgrades and allow for service to be transferred back to Xcel Energy (Docket No. E002, E256/SA-25-192); and (4) whether to take action on Greater Minnesota Gas’ delayed filing of its Cold Weather Rule report, require utilities to develop disconnection and payment arrangement policies (and publicize them), and take any action on Greater Minnesota Gas’ delayed filing of its Cold Weather Rule report (Docket No. E, G999/PR-25-2).

FEDERAL ENERGY REGULATORY COMMISSION (FERC)

FERC held its July Open Meeting on July 24, 2025 from 10:00 a.m. to 11:00 a.m. ET. The Commission issued Order No. 909, Reliability Standards for Frequency and Voltage Protection Settings and Ride-Through for Inverter-Based Resources, which approved reliability standards aimed at protecting grid reliability as intermittent power generation technologies increase penetration of the grid.  The standards are the latest in the Commission’s series of grid reliability orders pertaining to inverter-based resources (IBRs), most commonly wind and solar generators.    

Developed by the North American Electric Reliability Corporation (NERC), the standards address issues regarding IBR performance and require IBRs to stay connected to the grid during voltage and frequency disturbances to avoid the loss of power from IBRs, also known as “ride-through” capability. The standards are a response to the broader directive in FERC’s Order No. 901, issued in October 2023, which instructed NERC to develop comprehensive IBR-related reliability standards over a three-year period.

The final rule largely adopts the proposals from the Commission’s December 2024 Notice of Proposed Rulemaking. Historically, most mandatory reliability standards were designed for traditional synchronous generators. IBRs use power electronics to convert direct current to alternating current.  Order No. 909 aims to ensure that IBRs are required to meet reliability expectations similar to synchronous generators. The final rule becomes effective 30 days after publication in the Federal Register.

Also at the July Open Meeting, FERC issued 192 FERC ¶ 61,077, which partially grants PJM’s Order Nos. 2023 and 2023-A compliance filing, and directs PJM to submit a further compliance filing, including any necessary revisions to its Tariff, within 60 days of the date of the order.  FERC granted PJM several independent entity variations, finding them to be just and reasonable, not unduly discriminatory, and consistent with the goals of Order Nos. 2023 and 2023-A. Notable independent entity variations include: retention of PJM’s three-phase cycle process instead of the pro forma cluster study structure; retention of PJM’s 180-day application window and 90-day review period instead of the pro forma 45-day window to accommodate PJM’s large volume of interconnection requests and provide more preparation time; approval of PJM’s request to hold scoping meetings by transmission owner zone, not RTO-wide, due to PJM’s large footprint; and retaining the unilateral interconnection customer option for a one-year commercial operation date extension post-Generator Interconnection Agreement execution instead of three years.

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[1] Per the CPUC’s Rules of Practice and Procedure Rule 14.3, comments on proposed decisions are due 20 days after issuance of the proposed decision, and reply comments are due five days thereafter.  Comments on draft resolutions are due 20 days after the draft resolution appears in the CPUC’s daily calendar, per Rule 14.5.

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