Advocacy at the California Public Utilities Commission (CPUC)

CEERT’s Regulatory Counsel Sara Steck Myers and Associate Regulatory Attorney Megan Myers act as advocates and intervenors before the CPUC and other regulatory agencies to ensure fairly pricing for clean power, improve renewable energy procurement planning, and strengthen implementation of the state’s Renewable Portfolio Standard (RPS). CEERT is helping lead the fight for innovative policies that reflect the true value, costs, and benefits of clean, renewable energy.

Recent Developments:

CEERT Meeting with Energy Division

On January 22, CEERT’s V. John White, Jim Caldwell, Sara Myers and Megan Myers met with Ed Randolph, Donald Brooks and Michelle Keto from the CPUC Energy Division.  Jim identified significant gas issues that affect electric reliability and cost, such as GHG emissions, the brittleness of the gas supply, and an overreliance on gas for electric reliability and resource adequacy (RA).  Jim emphasized that current CPUC proceedings use inappropriate modeling and do not aim for solutions to these issues, which are not being adequately addressed in the IRP and not prioritized in RA.  Resolving these issues requires a comprehensive, proactive strategy across all silos, new modeling, and a realignment of energy efficiency and demand response cost-effectiveness tests and program design to reflect reliability value.

CEERT asked why the CPUC suspended the comment period for the Effective Load Carrying Capability (ELCC) Ruling in the RA proceeding; Donald Brooks responded only that more information would be forthcoming.  We stressed that there is only half as much demand response on the system as there was five years ago, and that the brittle gas supply system is in need of a solution.  Donald Brooks said they did not get good responses to these questions in the Aliso Canyon proceeding.  Ed Randolph noted that the Energy Division has issues with the CAISO on when gas plants are actually retiring, and that the Aliso Canyon proceeding has been slow because of contracting issues.  He said he agreed with most of what CEERT was saying, and asked us to prepare a four-page paper to assist Energy Division with these matters.

CPUC Investigation of PG&E’s Governance and Safety Culture

The CPUC has recently taken actions in I.15-08-019, its 2015 Investigation of PG&E’s organizational structure and governance, including safety culture.  I.15-08-019 has produced a consultant report issued for comment in May 2017, with its 61 recommendations adopted on December 5, 2018 in D.18-11-050.

On December 21, Commissioner Picker issued a Scoping Memo and Ruling that states:

The future of PG&E may also be impacted by other actors beyond the Commission. The Legislature, the court appointed Federal Monitor, the various courts considering claims against PG&E, the Federal Energy Regulatory Commission, and the communities served by PG&E all have a role in determining PG&E’s future. As a publicly traded company, PG&E must also respond to the financial markets, and to the requirements of the vendors and other parties with which it conducts business.

The CPUC will next obtain input on ways to address the underlying issue of PG&E’s safety culture.  PG&E was directed to file a summary of PG&E and PG&E Corp.’s corporate structures, including different lines of business and organizational charts of senior leadership, as of September 1, 2010 and December 31, 2018.  This summary was due on January 16, with Comments on this background filing due on January 30 and Reply Comments on February 13.

Renewable Portfolio Standard (RPS) Program (R.15-02-020 and R.18-07-003)

On July 23, the CPUC issued R.18-07-003, an Order Instituting Rulemaking (OIR) to Continue Implementation and Administration, and Consider Further Development, of California’s RPS Program.  Comments were filed August 3.

On September 12, Administrative Law Judge (ALJ) Atamturk issued a Ruling Requesting Comments on Staff Proposal on Effective Load Carrying Capability (ELCC), Time of Delivery Factors, and Project Viability.  Comments were filed on October 5 and Reply Comments on October 15.  CEERT’s party status was confirmed at a September 24 Pre-Hearing Conference (PHC).

On October 4, the Commission issued D.18-09-031, which closes R.15-02-020.

On November 9, Assigned Commissioner (AC) Rechtschaffen issued a Scoping Memo and Ruling that grouped the issues to be determined in this proceeding into three areas: (1) implementing existing and new statutory requirements mandated during the course of this proceeding, (2) completing tasks identified in R.15-02-020 but not accomplished prior to this new OIR, and (3) continuing, reviewing and improving existing elements of the RPS program and identifying additional elements that could be developed.

The remaining schedule for the proceeding is:

  • Fourth Quarter 2018: Proposed Decision (PD) on 2018 RPS Procurement Plans
  • No Sooner than 30 Days after the PD: Commission Decision on 2018 RPS Procurement Plans
  • Second Quarter 2019: AC/ALJ Ruling on 2019 RPS Procurement Plans
  • 2019: PD on ELCC, time of delivery factors, and project viability
  • 2019: PD Implementing SB 100
  • To Be Determined: Workshop on RPS/IRP (Integrated Resource Planning) Coordination
  • 2019: ALJ Rulings/Commission Decision needed to coordinate with the IRP proceeding

On November 13, the CPUC issued D.18-11-004, implementing Assembly Bill 1923 provisions on interconnection rules for the Bioenergy Feed-In Tariff under the state’s RPS.  This decision finds that a facility may participate in the BioMAT program if it interconnects to an existing utility-owned, CAISO-controlled transmission line, and is built and operational as part of the transmission system (rather than the distribution system) as of the submittal date of the BioMAT applicant’s Program Participation Request.

The decision revises the definition of “strategically located” facilities, and confirms that the $300,000 cap on transmission system upgrades applies to a facility interconnecting to an existing transmission line.  It also confirms that Category 3 generation facilities may maintain their BioMAT program queue position if they drop out of the CAISO queue, as long as they resubmit an interconnection application within 30 days of executing a BioMAT contract and all other BioMAT requirements and timelines have been met.  The decision adopts the BioMAT program deposit amount for facilities that drop out of the CAISO interconnection queue, and directs PG&E, SCE and SDG&E to file and serve Tier 2 advice letters within 45 days incorporating these changes into their BioMAT tariffs, standard contracts, and ancillary documents.

RPS ReMAT (Renewable Market Adjusting Tariff) Program – On Hold per U.S. District Court Decision

On December 6, U.S. District Judge Donato issued an order granting summary judgment in favor of Winding Creek Solar LLC’s requests for relief from PG&E’s ReMAT program, and found that CPUC decisions establishing the ReMAT Program conflict with federal law (PURPA).  The decision effectively shut down the ReMAT program and foreclosed the investor-owned utilities (IOUs) from signing new ReMAT contracts.  Both sides appealed this Order and oral arguments are scheduled to be heard.

Public Utility Regulatory Policies Act (PURPA) (R.18-07-017)

On August 1 the Commission issued R.18-07-017 as a direct response to the U.S. District Court’s order in Winding Creek v. Peevey (see above).  The OIR will consider changes to California’s existing implementation of the federal PURPA for the state’s IOUs; adoption of a new standard offer contract to be available to any qualifying facility (QF) of 20 MW or less seeking to sell electricity to a Commission-jurisdictional utility pursuant to PURPA, and adoption of a price to be paid at the time of delivery when a QF has opted to sell as-available energy to the utility without a contract.  Comments on the OIR were filed on September 12, and Reply Comments on September 24.   On September 27 ALJ Allen held a PHC and stated that he did not see material issues of fact that support the need for evidentiary hearings.

On October 18 the Commission held a workshop on when and how to address cost allocation, the Energy Division’s cost allocation proposal, other parties’ proposals, and other existing contracting mechanisms.

On November 2, Assigned Commissioner Rechtschaffen issued a Scoping Memo and Ruling.  Parties filed comments on November 14 and Reply Comments on November 28.  A Proposed Decision and Final Decision are expected in the first quarter of 2019.

Integrated Resource Planning (IRP) (R.16-02-007)

As previously reported, on February 28, 2018, several of the “Joint Parties” to the Diablo Canyon application filed a Petition for Modification (PFM) of D.18-02-018 to provide direction on the procurement of GHG-free resources to prevent any increase in GHG emissions after the Diablo Canyon generators are retired, as planned, in 2024 – 2025.  On March 26, CEERT and other parties (the “Environmental Responders”) filed a Joint Response that strongly supported additional CPUC consideration of the impact of Diablo Canyon’s retirement within the IRP proceeding.  There has not yet been a ruling on the PFM.

The Load-Serving Entities (LSEs) filed their IRPs on August 1, followed by an August 7 IRP Workshop on LSE Plans.   The workshop was organized around panels of LSEs by type (large investor-owned utilities (IOUs), small land multi-jurisdictional utilities, Community Choice Aggregators (CCAs) and Electric Service Providers (ESPs)).  There was also a panel of non-LSE stakeholders, including the CAISO, The Utility Reform Network (TURN), and California Environmental Justice Alliance (CEJA).

On August 10 the Modeling Advisory Group held a meeting on a Comparison of GHG Emissions between CAISO 2017 and RESOLVE 2018.  Energy Division/E3 found 5 million metric tons (MMT) of discrepancies worth investigating in the IRP model.

On September 12, CEERT filed Comments on the IRPs, arguing that both the PG&E IRP and the System Plan fail to prevent a GHG increase due to Diablo Canyon’s retirement, and the CPUC should therefore initiate explicit procurement of GHG-free replacement power.  We held that the SCE Preferred Portfolio should be approved regardless of other LSE plans, and the Pathway System Plan should be considered in the Reference System Plan of the next IRP cycle.  We noted that all LSE projected GHG emissions from the Clean Net Short Methodology are artificially low due to discrepancies in the RESOLVE model.

CEERT argued that the CPUC should clarify how new contracts with existing hydro resources can be used to meet GHG targets; that future LSE IRPs should have a requirement that LSEs report whether planned procurement is with new or existing resources; that LSE IRPs are the ideal place to connect the IRP to local RA requirements; and that SCE’s reliability threshold mechanism should be considered for all service territories, but with inclusion of all preferred resources.

On September 14, ALJ Fitch issued a Ruling that included a Guide to Production Cost Modeling in the IRP Proceeding and PowerPoint slides on production cost modeling and analysis that CPUC Staff conducted on a version of the Reference System Plan calibrated to the California Energy Commission’s (CEC’s) Integrated Energy Policy Report (IEPR) demand forecast.

On October 10, CEERT filed Comments on this Ruling that focused on the proposed GHG target used in the Preferred System Plan.  We recommended that the CPUC adopt a 42 million metric ton (MMT) GHG emissions target for the Plan, and that the modelling assumptions in the 2019-2020 IRP cycle be updated to reflect gas fleet retirement.  We also recommended that the CPUC develop sensitivities to investigate how preferred resources can mitigate reliability issues when gas units retire.

On October 31, the CPUC held a workshop on the production cost modeling for the IRP process and aggregated LSE IRP portfolios that featured Energy Division presentations on party comments about the production cost modeling, the way Staff aggregated and analyzed LSE pans, and the resource portfolios that Staff propose to serve as the Preferred System Portfolio for IRP and to transmit to CAISO for its Transmission Planning Process (TPP).

CEERT’s V. John White attended the workshop and offered comments, stating that the CPUC should rethink how urgent it is to deliver precise scenarios to the CAISO given the deficiencies and discrepancies in the models.  John recommended that integration across LSEs be made more interactive to be transparent and to maximize resource sharing, and that there be another public hearing with other agencies to get a higher-level breakdown of production cost modeling and the IRP.  He also cautioned against having a modeling input that is RPS-only and does not include GHG reductions.

On November 15, ALJ Fitch issued a Ruling that finalizes the production cost modeling approach that CPUC Staff will use to analyze resource portfolios, leading to a recommendation for the Preferred System Plan (PSP) for the first cycle of the IRP process.  Parties that are conducting modeling informally submitted results to Staff for discussion at a January 3 workshop.  A January 7 workshop presented Staff and modeling parties’ production cost modeling and other analytical results, and a Ruling issued on January 11 sought comment on the proposed PSP.

On November 16, Commissioner Randolph and ALJ Fitch issued a Ruling seeking input from parties on how to address emerging electricity market issues in the near-to-medium term that may affect overall electric system reliability.  In Comments filed December 20, CEERT focused on the need to transition from dependence on gas-fired resources for reliability, and to use non-emitting resources to meet local capacity requirements.  We urged the CPUC to develop a strategic plan to replace GHG-emitting resources for meeting short-, medium- and long-term capacity and reliability needs.  This effort is essential to meeting the goals of SB 100, and will take greater coordination between the IRP and RA proceedings.

On January 14, CEERT filed Reply Comments on the Policy Issues Ruling, and again urged the CPUC to develop a comprehensive strategic plan with the CAISO to replace GHG-emitting resources for meeting reliability needs.  We recommended that the CPUC develop both reactive and proactive approaches to the transition to low-carbon local reliability.

CEERT received support in Reply Comments from California Energy Storage Alliance, California Environmental Justice Alliance and Sierra Club (CEJA/SC), Eagle Crest Energy (ECE), and SCE.  CEJA/SC and SCE agreed with us that the CPUC must develop a strategy for an orderly retirement of gas generators that currently supply capacity and reliability services.  ECE agreed that the CPUC should evaluate coordinated procurement of high-cost resources and residual GHG-free resources that are too large to be procured by individual LSEs, but that are needed to meet the state’s GHG goals.  ECE also agreed that the focus of the IRP should be long-term reliability solutions.

On November 29, ALJ Fitch issued a Ruling seeking comments on the proposed inputs and assumptions for the 2019 Reference System Plan development and the proposed approach for estimating criteria pollutant emissions.  On January 4, CEERT filed Opening Comments that focused on the disadvantages inherent in RESOLVE, and recommended that the CPUC reevaluate approaches to take for system planning, with additional modeling conducted during development of the Reference System Plan.

On January 15, CEERT filed Reply Comments on the Inputs and Assumptions Ruling, highlighting that many parties have issues with the RESOLVE model and the CPUC should reevaluate modeling approaches for system planning.  Many parties, including Green Power Institute (GPI), Large-Scale Solar Association (LSA), NRG, PG&E and SCE, supported CEERT’s positions in our Opening Comments.  GPI and LSA agreed with us about RESOLVE issues.  NRG noted that CEERT advocated for a more granular, bottom-up approach to modeling.  PG&E supported CEERT’s request for a joint agency En Banc meeting for the CPUC, CEC, CARB and CAISO to begin SB 100 implementation efforts and share their visions for initiating a joint-agency study process.  SCE agreed with CEERT that the CPUC should conduct studies on gas plant retirements or build functionality to retire such resources into IRP modeling.

On January 7, the CPUC held a workshop on IRP Modeling Results for the 2018 Reference System Plan, discussing results of the hybrid conforming portfolio and recommending portfolios for the CAISO Transmission Planning Process (TPP).  Workshop Materials can be found on the CPUC website.

On January 11, ALJ Fitch issued a Ruling Seeking Comment on Proposed Preferred System Portfolio and Transmission Planning Process Recommendations.  This Ruling contains the recommended portfolio for the Preferred System Plan for the 2017-2018 IRP cycle, which is designed to move California’s electric sector toward the goals of SB 350, and seeks comments on the analysis behind the recommendation, whether the recommended preferred system portfolio is reasonable, and any actions the CPUC should take as a result of the portfolio.

Resource Adequacy (RA) (R.17-09-020)

At an August 1 PHC in Track 2 of the RA proceeding, ALJ Allen determined parties should submit comments instead of testimony, and in an August 1 e-mail Ruling, he requested that those comments include recommendations for process, scope and scheduling for Track 2 and substantive responses to the Opening Testimony and Proposals served on July 10.

On August 8, CEERT filed Comments on Track 2 process, scope and scheduling, noting that the highest priority issue in Track 2 is for the CPUC to develop RA counting rules for preferred resources and hybrid resources.  We recommended a Ruling seeking comments on such counting rules, followed by a workshop and legal briefs, and then a Decision adopting those rules.  We expressed concern that most of the Proposals submitted through testimony did not address the biggest long-term issues.

On August 31, ALJ Allen issued a Ruling allowing parties to file additional Track 2 comments.  On September 14, CEERT filed Comments recommending that any Track 2 decision to institute a multiyear procurement of local capacity requirement (LCR) needs from existing fossil resources must recognize current state law and emerging state energy policy.  We recommended that the CPUC adopt the community choice aggregator (CCA) proposal or a close variant thereof for the Track 2 decision on multiyear LCR procurement protocols.

We argued for adjusting the near-term LCR quantities adopted in Track 1 (which are to be procured from existing fossil resources on a multiyear basis under Track 2 protocols) to account for existing and planned preferred-resource procurements and transmission enhancements.  We recommended that the CPUC harmonize the RA and IRP protocols for procurement of new resources to meet LCR needs and incorporate a long-term plan for transition from fossil resources to supply LCR needs, consistent with state law.

On October 5, ALJ Allen issued a Ruling requesting Comments on SCE’s proposal for a central buyer to procure local RA on a residual basis up to 100% of established requirements.   Parties’ October 17 Comments and October 24 Reply Comments focused on how SCE’s proposal compares to the other full and residual proposals and on how it would be implemented, particularly in the context of the CAISO’s operational framework.

On November 15, the Energy Division issued a Monthly Effective Load Carrying Capacity (ELCC) Proposal for the 2020 RA Proceeding.  The Proposal presents Staff methodology and results for calculating ELCC percentages for four resource groups (wind; storage; solar; and wind, storage and solar combined), with the objective of informing party input on these results and on the best way to handle storage.

On November 21, ALJs Chiv and Allen issued a lengthy Proposed Decision (PD) that refines and adopts changes to the RA program, including identifying the distribution utilities as the central procurement entity for their distribution service areas and adopting specifications and requirements for implementing multiyear local procurement starting with the 2020 compliance year.

The PD notes that the Energy Division and several parties, including CEERT, support having the distribution utilities serve as central procurement entities for their distribution areas, and concludes that designating the distribution utilities as the central buyers for their Transmission Access Charge (TAC) areas is the most practical, feasible solution in the near term.  As this is the initial implementation of a multiyear local program, the CPUC will continue to monitor and evaluate the central procurement function and may modify the role or designate a different central buyer in future years, as appropriate.  The PD adopts a full procurement model in which the central buyers (one per TAC area) shall procure for local resources within their service areas to effectively and efficiently meet load area needs and reduce backstop procurement.

The PD adopts a minimum three-year forward multiyear RA requirement, and minimum central procurement percentages of 100% for Years 1 and 2 and 80% for Year 3.  The minimum requirement does not preclude contracts exceeding three years, and the minimum percentages do not preclude larger amounts; the PD encourages central buyers to enter into longer-term contracts and to exceed the minimum percentages if it is in the ratepayers’ interests to do so.

The PD directs central buyers to conduct solicitations for multiyear local RA procurement that are transparent, competitive, and open to all resources.  Any existing local resource that does not have a contract, any new local resource that can be brought online in time to meet solicitation requirements, and any LSE or third party with an existing local RA contract may bid into the solicitation.  LSE-procured local resources not selected may still count toward the LSE’s system or flexible RA obligations, if applicable.

The PD deems it reasonable to continue to treat local DR resources as is currently done in the year-ahead timeframe.  Central buyers are directed to establish a balancing account in order to facilitate the cost recovery process.  The PD adopts a procurement review group to advise on multiyear central procurement as an appropriate safeguard.  There will also be an independent evaluator process.

The PD adopts a process whereby a procurement action is deemed reasonable and preapproved if the resource that the central buyer procures (1) meets the established LCRs and underlying data supporting those requirements, which are based on the CAISO’s Local Capacity Requirement Technical Studies and adopted annually by CPUC decision; (2) if the procurement review group was properly consulted; and (3) if procurement was deemed by the independent evaluator to have followed all relevant CPUC guidance, including least-cost, best-fit methodology and other noted selection criteria.

For the multiyear local RA program, central buyers shall prepare an annual compliance filing that includes all contract terms and the criteria and methodology used to select local RA resources.  The CPUC directs each distribution utility to establish a rule or procedure that will govern how confidential, market-sensitive information that the distribution utility receives from generators, LSEs, or third-party marketers will be protected, and what firewall safeguards will be implemented to prevent the sharing of information beyond those employees involved in the central solicitation and procurement process.  The distribution utilities shall file and serve their proposed rule into the RA proceeding.  Once the proposals are submitted, parties will have an opportunity to comment, and the proposals will be addressed in Track 3.

The PD states that central buyers should not be assessed fines or penalties for failing to procure resources to meet the local RA requirements, as long as they exercise reasonable efforts to secure capacity and the independent evaluator report contains the reasons for failures to procure.

The CPUC declines to adopt multiyear requirements for system and flexible RA at this time, but notes that there may be potential benefits to expanding multiyear requirements to system and flexible RA, and will continue to monitor and evaluate the multiyear local RA program to consider such expansion in the future.  CAISO backstop mechanisms should not be expanded beyond an annual process at this point, as that would interfere with efficient procurement of local RA through the CPUC’s RA program.

As for transparency, the CPUC directs Energy Division to post a summary list early each calendar year of the resources listed on each LSE’s monthly RA plans for the previous year, including scheduling resource ID, scheduling coordinator ID or counterparty, zonal location, and local area (if applicable).

On December 11, CEERT filed Opening Comments, arguing that the PD must be modified to comply with the recently enacted SB 1136, which made changes to P.U. Code Section 380.  In ordering that the “distribution utilities shall serve as the central buyer for their respective distribution service areas,” the CPUC overlooks two subsections of P.U. Code Section 380 in favor of another and ignores SB 1136.

The PD strips local LSEs of any authority to address local reliability issues as California moves to a grid with a distributed structure and increasing amounts of preferred resources.  These local LSEs have, or are gaining, the resources, knowledge and experience to deal with local reliability issues in a manner consistent with the policy mandates in P.U. Code Section 380 and SB 1136.  Recent legislative direction recognizes the need for fundamental changes in RA to deal with the reality of the grid of the future, and such changes should be developed in a lengthy, robust process at the CPUC.  The PD needs to consider these factors before it embarks on significant changes to current RA architecture.

On December 17, CEERT filed Reply Comments in which we shared the concerns expressed by multiple parties about the PD’s proposed refinements to the RA program.   We strongly concurred with other parties that the overarching theme of reform of LCR is to ensure reliability and the financial stability of all resources, including residual existing fossil resources, necessary to achieve this goal.  We recommended that the central buyer requirement be further examined and, at the least, that the CPUC postpone implementation to 2021 and adopt a residual rather than full procurement by the central procurement entity, with full credit for existing LCR contracts and ongoing self-supply options by all LSEs.

On December 4, ALJ Allen issued a Ruling on ELCC, and attached the Energy Division’s Monthly ELCC Proposal for the 2020 RA proceeding.  The attachment provides the Energy Division’s methodology and results for calculating ELCC percentages for four resource groups: wind; storage (including batteries and pumped storage); solar; and wind, storage, and solar combined.  CEERT will file comments; however, on January 2 ALJ Allen suspended the due dates for comments, which will be rescheduled.

On December 4 ALJ Chiv sent an e-mail with the following tentative Track 3 calendar:

Track 3 Calendar – Excluding LCR and Flexible Capacity Requirement (FCR) Issues

  • February 20-21: Workshop on Energy Division and Party Proposals
  • March 8: Comments on the Workshop and Proposals due
  • March 22: Reply Comments on the Workshops and Proposals due
  • May: Proposed Decision on Track 3
  • June: Final Decision on Track 3

Track 3 Calendar – LCR and FCR Issues

  • April 4: CAISO files draft 2020 LCR and FCR Reports
  • April 18: Comments on draft 2020 LCR and FCR Reports due
  • May 1: CAISO files final 2020 LCR and FCR Reports
  • May 8: Comments on final 2020 LCR and FCR Reports due
  • May 14: Reply Comments on final 2020 LCR and FCR Reports due

On January 4, Commissioner Guzman Aceves held an All Party Meeting in this proceeding, with Commissioner Rechtschaffen also present.  Many parties expressed concerns about the PD, particularly on the central buyer and whether there should be residual or full procurement.  SDG&E stated that it does not have the capacity to be the central buyer in 2019, and most parties supported a true residual procurement.

CEERT’s Jim Caldwell noted that in the next 10 years we will roughly double the market share of renewables, which will cut gas in half.  Unless and until we develop local capacity resources that do not burn fossil fuels in the near-term, we will continue to shuffle the deck chairs with LCR.  Jim further noted that dispatch rights issues have not been litigated, but it will be very important to address those rights.

Aliso Canyon (I.17-02-002)

On August 21, ALJ Semcer issued a Ruling adopting an updated Phase 1 schedule in this proceeding.   And on August 28, the California Council on Science and Technology held a workshop on natural gas storage fields that covered a qualitative comparison of the risks of individual gas storage fields, public health findings, reliability, and possible future pathways.

On September 14, ALJ Semcer issued a Ruling that entered into the record the Energy Division’s “Scenarios Framework: Investigation 17-02-002.”  With reliance on its internal modeling team and Los Alamos National Laboratory, Energy Division updated and refined three proposed models (hydraulic, economic and production cost) that will inform this Order Instituting Investigation.  The models will examine whether or not the Aliso Canyon gas storage facility is needed for reliability and what the impact on costs would be if Aliso Canyon were closed or operated at a level of inventory lower than historic norms.  Parties filed comments on October 9 and Reply Comments on October 23.

In the related I.17-03-002 proceeding, on October 5 the Commissioners adopted D.18-09-032, which finds that Aliso Canyon was not out of service for nine consecutive months or longer in the aftermath of events following the gas leak that began on October 23, 2015.  Although there was a temporary moratorium on gas injections, Aliso Canyon remained available for service, supporting system balancing and reliability requirements, and therefore it is not necessary to resolve parties’ disputes about whether or how the facility may alternatively qualify as a plant held for future use for ratemaking purposes.

On December 10, the Energy Division issued “Winter 2017-18 SoCalGas Conditions and Operations Report,” which presents analyses of gas and electric system operations in Southern California from November 2017 to March 2018, and provides a summary of weather and system occurrences, operational actions taken, and lessons learned for future system operations and policy making, with a focus on Aliso Canyon.

On January 4, Assigned Commissioner Randolph and ALJ Semcer issued a Ruling that adopts the Energy Division’s “Scenarios Framework: Investigation 17-02-002” and closes Phase 1 of this proceeding.  The Scenarios Framework sets forth the methodologies and framework for the modeling studies needed to inform this OIR.  Phase 2 will undertake modeling efforts adopted in Phase 1 and will consider model results, as well as additional data and models presented by parties, in order to determine the impact of minimizing or eliminating the use of Aliso Canyon.  A Scoping Memo for Phase 2 will be issued soon.

On January 11, the CPUC and the CEC hosted a joint workshop that discussed the IEPR, recently high natural gas prices in Southern California, and solutions to reduce the spread between SoCal Border and SoCal Citygate prices.  These potential solutions could impact the Aliso Canyon proceeding.  On January 14, ALJ Semcer issued a Ruling entering into the record an updated Scenarios Framework.

SoCalGas and SDG&E Application for Low Operational Flow Order (OFO) and Emergency Flow Order Requirements (A.14-06-021)

SCE and Southern California Generation Coalition (SCGC) filed a Joint Petition for Modification (PFM) of D.15-06-004 and D.16-06-039.  On January 15, Commissioner Randolph issued a Scoping Memo that found the issues raised in the PFM are now issues in this proceeding, as follows:

  1. The current Low OFO penalty structure assumes sufficient gas can be brought into the market to supply noncore customers, but realistically this is not always the case in the current environment, due to reduced transmission capacity and the unavailability of Aliso Canyon storage for noncore customers.
  2. Marketers are increasing their prices, knowing that the price may be set by the very high noncompliance charge.
  3. It is often the case that little supply is readily available at reasonable prices after Cycle 1 of the SoCalGas nomination day.
  4. There is a mismatch between the SoCalGas nomination cycles and the power market.
  5. Large costs are being incurred by noncore customers, including electric generators.
  6. SoCalGas has been defaulting to only a 5% tolerance, even though a higher tolerance could potentially be allowed in some cases.
  7. Is there a linkage between the level of the noncompliance charges and the price spikes that occurred recently when Low OFOs were called?
  8. Would lowering SoCalGas’ OFO penalty create a mismatch between SoCalGas’ and PG&E’s OFO penalties?
  9. Would widening the gap between the $5/Dth OFO and the $50 Emergency OFO increase the number of Emergency OFOs and increase gas market volatility?
  10. If the Commission rejects the reduction requested in the PFM, should the Commission consider a more conservative change to the penalty structure such as a graduated penalty structure?
  11. Should any reduction be temporary – meaning that a more permanent structure should be developed in a current proceeding, or new proceeding or this proceeding?
  12. Are there any safety issues that the Commission needs to address as a result of the Joint PFM?

Evidentiary hearings will be held March 11-12, with Opening Briefs due on April 2 and Reply Briefs on April 12.  A Proposed Decision will be issued June 14.

Diablo Canyon (A.16-08-006)

On December 7, the CPUC issued D.18-11-024, modifying the outcome of D.18-01-022, which authorized closure of the Diablo Canyon nuclear power plant.  In compliance with SB 1090, PG&E can collect an additional $225.8 million in rates over the amounts authorized in D.18-01-022.  SB 1090 added Section 712.7 to the P.U. Code and directed the CPUC to approve full funding for the proposed community impact mitigation and employee retention programs.  This proceeding is again closed.

SCE Requests for Proposals (RFPs)

SCE Moorpark:  On July 30, SCE circulated a Revised Moorpark Sub-Area Local Capacity Requirements Procurement Plan.  On September 7, CEERT submitted Comments supporting the Plan and commending SCE for allowing the bidding of hybrid storage resources, and for proposing a methodology for counting these resources for LCR.  We recommended that there be a specific plan to monitor real-world results of deployment of hybrid storage resources, and to expand the use of hybrid resources to include packages with individual components that do not meet LCR criteria.

On November 29, the CPUC approved the Revised Moorpark Plan, stipulating that any proposed procurement be submitted via application.  The application will initiate a new proceeding in which interested parties will have the opportunity to raise concerns, with the CPUC ultimately deciding the reasonableness of SCE’s proposed procurement.

SCE Preferred Resources Pilot RFPs:  On July 20, the CPUC issued D.18-07-023 approving the results of SCE’s PRP-2 procurement.  On August 20, the Office of Ratepayer Advocates (ORA), which always opposed SCE’s PRP-2, filed an Application for Rehearing of D.18-07-023.  ORA argues that D.18-07-023 commits legal error because it violates the CPUC’s own procedure rules, decides issues beyond those the proceeding’s Scoping Memo, alters the Scoping Memo without providing ORA notice and an opportunity to be heard, violates and fails to apply applicable statutes, relies on out-of-date data, lacks a sufficient evidentiary record, issues inconsistent findings, fails to issue findings on all issues material to the Decision, and violates the CPUC’s obligation to ensure that rates are just and reasonable.

Demand Response (DR) (R.13-09-011)

On July 18, SCE, on behalf of workshop participants, filed a Petition for Modification that proposes changes to D.17-10-017 to enable a more effective and less confusing implementation of the CPUC’s competitive neutrality cost causation directives.  The workshop participants request changes to D.17-10-017 to confirm compliance obligations of the IOUs and third-party DR aggregators when communicating to customers.  Responses to the PFM were filed August 2.

On October 26, the CPUC issued Resolution G-3541 approving $5,870,000 for SoCalGas to reduce gas heating load during periods of system constraint by controlling residential thermostats.  SoCalGas had requested $5.9 million to operate a 2018-2019 winter season smart thermostat load-control DR program.

DR Applications (A.17-01-012, et al.)

On August 6, ALJ Hymes issued a Ruling Directing Responses to Questions on the Demand Response Auction Mechanism (DRAM) Pilot.  Responses were filed on August 17 and Replies on August 22.  On October 25, ALJs Hymes and Atamturk issued a Proposed Decision (PD) Resolving Remaining Application Issues for 2018-2022 DR Portfolios and Declining to Authorize Additional DRAM Pilot Solicitations.  Comments were filed on November 14 and Reply Comments on November 19.

On November 29, the CPUC voted to adopt the PD, and Final Decision D.18-11-029 was issued December 10.  This Decision adopts: 1) the prohibition of dual participation in Critical Peak Pricing and another DR program for all new customers, beginning immediately and until further notice; 2) the prioritization of third-party customers in the allocation of any remaining megawatts under the two percent reliability cap; 3) Auto Demand Response (ADR) policies to be included in revised ADR Control Incentives Guidelines and Adopted Policies, and a process to pursue further technical refinements to the guidelines and ADR;
4) a stakeholder process to develop an overall strategy proposal for battery storage; and 5) guidelines for pilots targeting DR and a regulatory process for submittal and approval of the pilot proposals.

Until the evaluation of the DRAM pilot has been completed and reviewed, the CPUC should not authorize funding for additional auctions.  This proceeding remains open to review the evaluation and staff recommendations for the DRAM pilot, and to determine a strategy and policies for battery storage controls in ADR.  All other issues in this proceeding have been resolved.

On November 30, ALJ Hymes issued a Ruling noticing a PHC to discuss the IOUs’ filings on the Federal Energy Regulatory Commission (FERC) Tariff Amendment to Implement Energy Storage and DER Requirements, and to discuss next steps for determining DR baselines.  Parties filed PHC Statements on January 3, and on January 10 ALJ Hymes held the PHC to address the following questions:

  • What issues should the Commission consider in determining whether to revise the current baseline?
  • Will these issues result in the need for an evidentiary hearing?
  • Is testimony needed, or is a workshop and comments and reply comments the appropriate approach?
  • Can the Commission can adopt a baseline for DR programs by the statutory deadline of July 17?

On January 4, ALJ Hymes issued a Ruling Issuing Evaluation Report of the DRAM Pilot, Noticing January 16 Workshop, and Denying Motion to Require Audit Reports in the Evaluation Report.  On January 11, parties filed proposed improvements to the DRAM.  A DRAM workshop was held on January 16, followed by a January 31 workshop on ADR and battery storage controls and a February 11-12 workshop on proposed DRAM improvements.

Prohibited Resources (A.18-10-008, et al.)

On October 19, the IOUs filed Applications on prohibited DR resources.  On November 27, ALJ Hymes issued a Ruling that consolidated the applications and set a PHC for January 10, when she identified two issues: whether costs from metering or logging are reasonable for DR incentives, and whether the CPUC should direct the IOUs to require customer installation of metering or data logger equipment for verification process.

Draft California Customer Choice Green Book

In December the Energy Division drafted the California Customer Choice Project Choice Action Plan and Gap Analysis, which was circulated on January 3.  The Choice Project Plan offers a roadmap to anticipate and ameliorate the adverse and unintended consequences of customer choice and disaggregated electricity procurement.  The CPUC will implement these recommendations through relevant initiatives to address increasing customer choice in California in 2019.

Other CPUC Rulemakings and Governance Actions:

CEERT has had a limited budget to actively participate in other CPUC issues.  Nevertheless, we are currently a party to or are tracking the following proceedings in order to advance key resources.

Power Charge Indifference Adjustment (PCIA) (R.17-06-026)

On August 1, ALJ Roscow issued a Proposed Decision (PD) Modifying the PCIA.  The PD adopted revised inputs to the market price benchmark (MPB) that is used to calculate the PCIA, the rate intended to equalize cost sharing between departing load and bundled load.  The PD also adopted an annual true-up mechanism, as recommended by a number of parties, as a cap that will limit the change in the PCIA rate from year to year, ensure that bundled and departing load customers pay equally for the above-market costs of PCIA-eligible resources, and provide a degree of the rate stability and predictability sought by departing-load interests.  Comments were filed on August 21 and Reply Comments on August 27.

Oral arguments were held on August 2.  The IOUs mostly objected to the PD, and California CCA mostly supported the PD.  On August 14, Commissioner Peterman issued an APD.  The main difference between the PD and the APD was that the APD found legacy utility-owned generation (UOG) is PCIA eligible and should be recovered from CCA customers, but the PD did not.  Unlike the PD, the APD also terminated the 10-year limit on PCIA cost recovery for post-2002 UOG and certain storage costs; established a PCIA collar starting in 2020, with the cap limiting upward or downward changes in the PCIA to 25% in either direction from the prior year; and, for the 2019 ERRA forecasts only, adopted the Platt’s Portfolio Content Category 1 REC index value for the MPB’s RPS Adder.  Comments on the APD were filed on September 4 and Reply Comments on September 10.

An All-Party Meeting was held on September 7.  On September 20, the CPUC issued D.18-09-013 approving a Track 1 Settlement.  The settlement agreement provides that medical baseline customers of CCAs in PG&E’s service territory that begin to serve residential customers subsequent to this decision will receive a PCIA exemption. Payment of the PCIA by medical baseline residential customers of CCAs currently serving customers will be phased in over a period of four years.

The PD and APD were held twice, then voted on at the October 11 CPUC Business Meeting.  On October 19, the CPUC issued D.18-10-019, adopting Commissioner Peterman’s APD, and including revised inputs to the MPB, an annual true-up mechanism, a cap to limit the change of the PCIA rate, and an option for departing load customers to prepay their PCIA obligation.  A Phase 2 of the proceeding will consider development and implementation of a comprehensive solution to excess resources in utility portfolios.  At a December 19 PHC, the CPUC decided working groups should be established to address benchmark true-up; prepayment; portfolio optimization and cost reduction; and allocation and auction.

Distribution Resource Plans (DRPs) (R.14-08-013)

On September 4, ALJ Mason issued a Ruling on the Distribution Planning Advisory Group (DPAG), and requested comments on September 11 on whether to extend the scope of the DPAG agenda for the next year to provide preliminary evaluation of recent distributed energy resource (DER) solicitations to inform the IOUs’ process for this cycle.  The minimum required scope of the DPAG encompasses a review of planning assumptions and grid needs in the Grid Needs Assessment, planned investments and candidate deferral opportunities in the Distribution Deferral Opportunities Report, and candidate deferral prioritization.  To meet the objectives of the process, the IOUs need to enable members to review the materials, get further clarification, and provide feedback on the candidate shortlist and solicitation requirements.

On September 14, the CPUC issued two resolutions.  Final Resolution E-4934 approves SDG&E’s Advice Letter on Demonstration Project C Request for Offer (RFO) bidding results, and approves SDG&E’s request to include DRP Demonstration Project C RFOs without executing any contracts.  Final Resolution E-4941 approves PG&E’s filing on DRP Demonstration Project C RFO results, and approves PG&E’s request to conclude the DRP Demonstration Project C RFOs without executing any contracts.

On December 17, ALJ Mason issued a Ruling Resolving Confidentiality Claims Raised by PG&E, SCE and SDG&E as to Distribution Planning Data Ordered by D.17-09-026 and D.18-12-004.  The Ruling finds that the IOUs have failed to carry their burden of proving that the information they wish to redact from their soon-to-be-made-public online maps or make subject to a non-disclosure agreement meets the definition of Critical Electrical Infrastructure Information that should be protected from public disclosure on confidentiality (i.e., physical or cybersecurity) grounds.

The Ruling allows stakeholders and interested parties to have access to the online maps without having to execute a non-disclosure agreement if they comply with the registration process described in the Ruling, and orders the IOUs to make available online, through their DRP portals, the Integration Capacity Analysis and Locational Net Benefits Analysis maps and underlying data, and the Grid Needs Assessment and Distribution Deferral Opportunities Report data required by D.17-09-026 and D.18-12-004.

Integration of Distributed Energy Resources (IDER) (R.14-10-003)

On August 13-14, the CPUC held a workshop to discuss the Amended Scoping Memo issued on February 12, 2018.  The workshop discussed review of statutory and CPUC directives in R.14-10-003, DERs, streamlining the competitive solicitation framework, alternatives to the competitive solicitation framework, coordinating current activities to maximize locational benefits and minimize costs, DER tariffs, and development of a prequalification process.

On September 17, ALJ Hymes issued a Ruling Directing Responses to Questions Regarding Contracts to Update the Avoided Cost Calculator (ACC) and Related Work.  Responses were filed on September 27 and Replies on October 2.  The Ruling set forth questions about utility-administered contracts.

On October 26, the Commission issued Redacted Resolution E-4956, which approves PG&E’s request to procure a DER solution for the IDER Incentive Pilot Candidate Project at the Gonzales Substation.

DER Improvements to Rule 21 (R.17-07-007)

On August 15, ALJ Hymes issued a Ruling Directing Responses to Questions on Working Group One Report and Granting in Part the IREC Motion to Modify Schedule in this proceeding.  Comments/Responses were filed on September 5 and Reply Comments/Replies on September 12.

On December 7, ALJ Hymes issued a Ruling Directing Responses to Questions on Working Group Two Report.  Responses are due on February 1 and Reply Comments on February 22.  Working Group Two developed the following proposals addressing several issues in the scoping memo:

  • Issue 6 Proposal: Develop forms and agreements to allow DER Aggregators to fulfill Rule 21 requirements (but there was non-consensus on this issue).
  • Issue 8 Proposal: Stakeholders developed the following issues on Issue 8:
    • Proposal 8.a. Remove Existing Fast Track Eligibility Limit (Consensus).
    • Proposal 8.b. Modification of Initial Review Process to Include Verification and Explanation of Updated Integrated Capacity Analysis (ICA) (Non-Consensus).
    • Proposal 8.c. Track when ICA Values are Updated Outside of the Required Monthly Update to Inform Future ICA Discussions (Non-Consensus).
    • Proposal 8.d. Modification of Projects if ICA Values are Out-of-Date to Stay Under ICA Limit and Maintain Queue Position (Non-Consensus).
    • Proposal 8.f.1. Adopt Additional Initial Review Screen F1 (Consensus).
    • Proposals 8.f, 8.g, 8.h, and 8.j. Apply Screen F, G, H and J only to Projects larger than 30 kVa; Provide Earliest Available Indication where Screen F and G Failure is Likely (Modification 1 (Consensus) and Modification 2 (Non-Consensus)).
    • Proposal 8.i. Consider Applicability of Screen I for Non-exporting Projects Above 30 kVa (Non-Consensus).
    • Proposal 8.k. Modify Screen L to Include the Transmission Overvoltage and Transmission Anti-Islanding Test (Non-Consensus).
    • Proposal 8.l. Provide Earliest Available Indication where Screen L Failure is Likely (Non-Consensus).
    • Proposal 8.m. Screen M should be modified to reflect ICA (Non-Consensus).
    • Proposal 8.n. Update Screen N Methodology (Non-Consensus).
    • Proposal 8.q. Modify Screen P (Consensus).
    • Proposal 8.r. The Interconnection Application Should have an Option to Combine Initial Review and Supplemental Review, with Applicants Pre-Paying for Initial Review and Supplemental Review (Consensus).
    • Proposal 8.s. Reduce Interconnection Application Fee for non-Net Energy Metering (NEM) Systems (Non-Consensus).
    • Proposal 8.t. Queue Management (Non-Consensus).
    • Proposal 8.v. Additional Automation and Streamlining Opportunities Proposal (Non-Consensus).
  • Issue 9 Proposal: Allow Interconnecting DER to be Evaluated and Operate Under Limited Generation Profile (Non-Consensus).
  • Issue 10 Proposal: Standardize Utility Processes and Timelines for Interconnection Applications to be reviewed under Rule 2, Rule 15 and Rule 16 (Consensus and Non-Consensus on sub-proposals).
  • Issue 11 Proposal: Expedite Interconnection Applications for Non-Export Storage Systems (Non-Consensus).

Energy Efficiency (EE) (R.13-11-005)

On October 12, the CPUC issued Resolution E-4939, which addresses Track 2 Working Group (T2WG)-related energy efficiency issues.  This Resolution adopts the proposed T2WG standard practice baseline definition and baseline selection process with modifications and clarifications, adopts the T2WG proposal to use a single preponderance of evidence requirement process for all accelerated-replacement measure types with clarifications, and adopts a T2WG proposal to identify a small-sized business customer.

On October 12, the CPUC issued Resolution E-4952, which approves Database for Energy-Efficient Resources (DEER) updates for 2020 and a revised version of the 2019 DEER.  On January 11, Marin Clean Energy held a workshop to discuss its Annual Budget Advice Letter and gather recommendations for its portfolio of EE programs to ensure that the portfolio meets or exceeds a 1.0 Total Resource Cost (TRC) on an evaluated basis and moves toward the goal of a forecast TRC of at least 1.25 by 2023.  On January 30, SoCalGas hosted an ABAL workshop to explain its forecasted 2019 EE Portfolio.

EE Business Plans (A.17-01-013, et al.)

On August 29, ALJ Fitch issued a Ruling Seeking Comment on Market Transformation Staff Proposal and scheduling a workshop for September 19.  Comments were filed on October 5 and Reply Comments on October 22.  On September 7, ALJ Fitch issued a Proposed Decision Addressing Workforce Requirements and Third-Party Contract Terms and Conditions in the energy efficiency rolling portfolio proceeding (R.13-11-005).  Comments were filed on September 27 and Reply Comments on October 3.

On October 22, the CPUC issued D.18-10-008 on workforce standards to be applied by EE program administrators (PAs) to all programs meeting certain size and measures criteria in their business plan portfolios.  The workforce standards are applied to large non-residential projects involving heating, ventilation and air-conditioning measures and lighting controls, and must be included in the first round of third-party solicitations beginning later this year and be in place for non-third-party programs by January 1.

The Decision sets forth the provisions of required standard and modifiable terms and conditions that utility PAs must include in their contracts with third-party designers and implementers of EE programs within their business plan portfolios.  The utilities are required to include all of the proposed standard contract terms in their joint motion for adoption of the terms, including those not specifically discussed in the Decision.  Non-utility PAs are also encouraged to use these contract terms.

Energy Storage Procurement Plans (A.18-02-016, et al.)

On October 31, the Commission issued D.18-10-036 approving the AB 2514 Energy Storage Procurement Plan components of the IOU’s applications.

On November 9, the CPUC issued Redacted Resolution E-4949 approving cost recovery for PG&E for three power purchase agreements and one engineering, procurement and construction agreement for four energy storage facilities with the following counterparties: mNOC, Dynegy, Hummingbird Energy Storage LLC, and Tesla.  The Resolution finds that the Moss Landing Energy Storage project does not require a certificate of public convenience and necessity or permit from the CPUC.

On October 10, CEERT submitted comments strongly supporting this Resolution, with the minor addition of allowing PG&E to recover prudent additional costs to reserve plot space and consider in the current design future electrical capacity expansion for potential additional inverters in future projects to improve cost-effective utilization of the existing battery installation.

Public Records Access (R.14-11-001)

On September 28, Assigned Commissioner Picker issued a Ruling that proposes a revision to General Order (GO) 66 D to ensure that the CPUC staff gets timely access to information.  Since GO 66 D went into effect in 2017, staff has experienced delays in obtaining information from regulated entities when performing audits, inspections, investigations, and enforcement. This is unacceptable.  Some regulated entities have cited Section 3 of GO 66 D as justification for not providing CPUC staff information (especially in the course of an on-site visit) because the regulated entity first needs time to review the information and possibly submit a claim of confidentiality.

The staff proposal attached to this ruling would revise GO 66 D to enable CPUC audit, inspection, investigation, and enforcement staff to obtain information immediately and allow the regulated entity 10 days to submit a claim of confidentiality.  During those 10 days, CPUC staff would protect the confidentiality of the information.  Opening Comments were filed on October 8 and Reply Comments on October 15.

On December 7, Commission President Picker issued a Proposed Decision implementing a revision to GO 66-D that CPUC Staff can invoke when necessary to expedite regulated entities’ submission of information.  Comments were filed on December 27 and Reply Comments on January 2.

Climate Change Adaptation (R.18-04-019)

On October 10, AC Guzman Aceves issued a Scoping Memo in this proceeding, which will have at least two phases.  Phase 1 will broadly consider how best to integrate climate change adaptation into larger electric and gas IOUs’ planning and operations to ensure safety and reliability of service, and will address five key topics: definition of climate adaptation for utilities; appropriate data sources, models and tools for climate adaptation decision-making; guidelines for utility climate adaptation assessment and planning; identification and prioritization of actions to address climate-change-related needs of vulnerable and disadvantaged communities; and a framework for climate-related decision-making and accountability.  The remaining Phase 1 schedule is:

  • Q4 2018 through Q2 2019: Working Group Process
  • Summer 2019: Final Set of Working Group Session Report Comments and Replies Received
  • 90 Days following Submission: Proposed Decision
  • September 2019: Commission Decision

SCE Application for Clean Energy Optimization Pilot (CEOP) (A.18-05-015)

On August 16 the Commission held a workshop to enable parties to discuss SCE’s proposal for CEOP to provide incentives for GHG reductions for participating UC and CSU campuses.  The workshop discussed CEOP program design, evaluation and lessons learned and interactions with existing programs.

On August 17, ALJ Kline issued a Ruling setting forth questions, with Comments filed on August 30 and Reply Comments on September 10.  The questions pertained to the reasonableness of the CEOP program design, modifications to program components, CEOP eligibility requirements, whether there is sufficient funding for the CEOP pilot, the outcome if funds are sufficient to cover CEOP funding, eligibility of CEOP for funding through Electric Program Investment Charge, and other issues.  Testimony was submitted on September 27 and Rebuttal Testimony on October 11.

Disconnections and Reconnections (R.18-07-005)

On September 12, ALJ Kelly issued a Ruling requesting information by September 28 from PG&E, SCE, SDG&E and SoCalGas on disconnection policies and guidance, effectiveness of previous policies and programs, payment/arrearage, reconnection policies, and credit and security deposits.  The Ruling requests that IOUs provide quarterly reports that include payment arrangements and bill assistance, broken payment arrangements, arrearages, disconnection/terminations, security deposits, notices and basic information.  On September 13, Commissioner Guzman Aceves issued a Phase 1 Scoping Memo and Ruling and Request for Comments on a Proposed Pilot Program.  This proceeding is quasi-legislative.

Remaining Schedule for Phase 1:

  • Spring 2019: Proposed Decision on Phase 1 issues followed by Comments and Reply Comments
  • Within 18 Months of Scoping Memo: Final Decision on Phase 1 issues

On October 30, Commissioner Guzman Aceves issued a Proposed Decision Adopting Interim Rules to Reduce Residential Customer Disconnections for California-Jurisdictional Energy Utilities.  Comments were filed on November 19 and Reply Comments on November 26.  The PD was discussed and held at the November 29 CPUC Business Meeting.  Commissioner Randolph requested that the PD be modified to put a sunset date on the interim rules.  Commissioner Peterman expressed concerns about the cap.

On December 19, the CPUC issued D.18-12-013 adopting interim rules to take effect immediately on an emergency basis to provide rapid relief while the CPUC considers longer-term solutions. These interim rules are applied to all gas and electric IOUs in California. The Decision imposes a goal for limiting disconnections to 2017 recorded levels per utility and modifies the existing rule prohibiting disconnections during extreme weather conditions. The utilities currently must not disconnect residential customers during extreme weather conditions based on a 24-hour look-ahead; this decision extends the look-ahead period from 24 to 72 hours.  In identifying vulnerable customers to be protected against disconnection, the CPUC shall include any household on medical baseline or life support and for customers age 65+.

Affordability (R.18-07-006)

On July 23, the CPUC issued R.18-07-006, an OIR to Develop Methods to Assess the Affordability Impacts of Utility Rate Requests and Commission Proceedings.  Parties filed Comments on August 13.  The proceeding has been reassigned from Commissioner Peterman to Commissioner Rechtschaffen.  A PHC was held on October 1.

On November 19, AC Rechtschaffen issued a Scoping Memo and Ruling.  The scope of the rulemaking covers: identification and definition of affordability criteria for CPUC-jurisdictional utility services, methods and processes for assessing affordability impacts across CPUC proceedings and utility services, and other utility services affordability issues.  Issues outside the scope of the proceeding are: affordability issues for customer classes other than residential, evaluation of existing affordability programs’ effectiveness or creation of new customer programs to assess affordability, new approaches to disconnections and reconnections, and PG&E’s Essential Use Study.  A workshop was held on January 22.

San Joaquin Valley Disadvantaged Communities (R.15-03-010)

On December 19, the CPUC issued D.18-12-015 approving $56 million for 11 Disadvantaged Communities Pilot Projects in the San Joaquin Valley.  PG&E and SCE will each serve as Pilot Administrators for three electrification pilots.  PG&E will issue and Energy Division staff will choose a competitive RFP to select one electrification Pilot Administrator and Pilot Implementer for five additional pilots.  The decision authorizes $5.61 million for SoCalGas to administer a pilot project in California City, and a limited opportunity for SoCalGas to locate additional gap funds for gas pilots in Allensworth and Seville.  At the December 13 CPUC Business Meeting, four Commissioners voted to adopt this Decision while Commission President Picker voted against it and noted that he would be filing a Dissent.

Transportation Electrification (R.18-12-006)

On December 13, the CPUC voted to adopt R.18-12-006, a new transportation electrification proceeding that continues the implementation and administration of transportation electrification programs, tariffs and policies at the Commission.  As a successor docket to R.13-11-007, the proceeding seeks to develop a comprehensive Transportation Electrification Framework (TEF).  Energy Division is directed to prepare a Staff Proposal including a draft TEF that will be served no later than 10 months after the December 19 issuance of this Rulemaking.