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:

Renewable Portfolio Standard (RPS) Program (R.15-02-020)

R.15-02-020 (RPS) has become more active in recent months. As previously reported, in February of 2017, Commissioner Rechtschaffen became the Assigned Commissioner of R.15-02-020.

On December 18, the CPUC issued D.17-12-007, which approved the draft 2017 RPS Procurement plans filed by Pacific Gas & Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E), and the requests of those three investor-owned utilities (IOUs) to forgo holding a 2017 RPS solicitation. The decision directs the IOUs to file final 2017 RPS Procurement Plans within 30 days.

D.17-12-007 authorizes the three IOUs to conduct solicitations for short-term (five years or less) sales of RPS volumes during the timeframe covered by the 2017 RPS Procurement Plans, or prior to the CPUC issuing a decision on the 2018 RPS Procurement Plans. The IOUs must submit a Tier 1 Advice Letter for CPUC approval of short-term sales resulting from a solicitation. The decision also approves the IOUs’ request to engage in bilateral transactions to sell RPS volumes, subject to the CPUC’s approval of completed transactions through a Tier 3 Advice Letter process that was established in D.09-06-050. Lastly, the decision accepts the draft 2017 RPS Procurement Plans filed by small and multi-jurisdictional utilities, community choice aggregators, and electric service providers. See:

On January 4, Administrative Law Judge (ALJ) Atamturk issued a Ruling seeking comments on how Senate Bill (SB) 350 impacts determination of penalties for noncompliance with and waivers of RPS procurement requirements, in order to inform a future CPUC decision on revisions to RPS enforcement rules. Opening Comments were due January 18, and Reply Comments were due January 29. See:

On January 18 the CPUC held a workshop on Effective Load Carrying Capability (ELCC), and on February 6 the Commission held a workshop on Least-Cost, Best Fit reform.

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 in Case No. 13-cv-04934-JD on PG&E’s ReMAT program, granting summary judgment in favor of Winding Creek Solar LLC. The order essentially finds that the CPUC decisions establishing the ReMAT Program conflict with federal law (PURPA). Although the objective of Winding Creek was to secure a contract and greater payments from PG&E under the program, the decision does not go that far, but instead, as interpreted by the CPUC, effectively shuts down the ReMAT program and forecloses any of the IOUs from signing new ReMAT contracts while the Commission continues to assess the order. See:

On January 3, the CPUC filed an “urgent motion” to the Court to stay its order while the Commission appealed it, or to allow the CPUC to seek a stay in the 9th Circuit. Among the allegations was what the CPUC sees as the broad effect of the order beyond the contract that Winding Creek challenged:

One, perhaps unintended, consequence of the Order and Judgment is to enjoin the CPUC from implementing the entirety of the Re-MAT program, not just procurement by PG&E for the product type for which Winding Creek is eligible. For example, the Order and Judgment also prevent the implementation of the CPUC’s recent expansion of the Re-MAT program, which includes a new product type, conduit hydroelectric generation up to 4 MW, as ordered by Cal. Pub. Util. Code § 399.20.5. See CPUC Decision 17-08-021, 2017 WL 3953989 (2017). While the electric utilities, other parties, and CPUC staff were finalizing the implementation of the expanded Re-MAT program, the CPUC suspended further progress in the Re-MAT program, effective immediately, due to this Court’s Order and Judgment.

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

On September 19, ALJ Fitch issued a Ruling Seeking Comment on the Proposed Reference System Plan (RSP) and Related Commission Policy Actions. The Proposed RSP contained a recommendation for the GHG emissions target to use in the IRP process for the California electric sector, as well as for the load serving entities (LSEs) representing the portion of the electric sector under the CPUC’s authority. The Proposed RSP also included a recommended portfolio of electricity resources for the portion of the grid that the CAISO serves. The Ruling, RSP, and Modeling Inputs and Assumptions can be found at:

On September 25 – 26, the CPUC held a workshop on the IRP RSP that covered the following topics: Proposed RSP, Relationship between IRP and CAISO’s Transmission Planning, Production Cost Modeling for IRP System Plans, Proposed CPUC Policy Actions, Recommended CPUC Policy Actions, and Path to Future All-Resource Planning.

On October 26 CEERT filed Opening Comments on the Ruling. We stressed the importance of adopting the 42 million metric ton (MMT) GHG emissions case, urged the CPUC to initiate tax-eligible procurement in 2018, and advocated that the CPUC re-evaluate long-term resources with appropriate GHG targets. See:

A November 2 All-Party Meeting in the IRP mostly consisted of a discussion by CPUC Staff on the proposed IRP process and RSP for 2017 – 2018. CEERT expressed support for early procurement to take advantage of the federal tax credits. The diversity of the system portfolio is going to become more important following gas plant retirements, and with the very likely closure of Diablo Canyon, the IRP is the first opportunity to procure GHG-free resources to mitigate that closure.

On November 9, CEERT and numerous other parties filed Reply Comments on the RSP Ruling. We again stressed the importance of expedited procurement because it is beneficial and necessary to fulfilling IRP requirements and meeting the 2030 GHG targets. We pointed out that diverse resources are undervalued in the model and should be appropriately included in the RSP. We also stated that early retirement of the gas fleet should be prioritized, and coordinated studies should begin immediately. See:

ALJ Fitch issued a Ruling Denying Motion for Evidentiary Hearings on November 27 and a Proposed Decision Setting Requirements for LSEs Filing IRPs on December 28. CEERT is filing Comments.

The Proposed Decision (PD) adopts a two-year planning cycle for the CPUC to conduct modeling and analysis, set GHG emissions targets, and consider IRP filings from all LSEs. Each LSE’s filing will need to include one scenario that conforms to the CPUC’s planning direction, and can also present, with appropriate justification, any LSE-preferred scenarios that deviate from CPUC planning standards.

The IRPs will be the vehicle for LSEs proposing actual procurement of additional resources to meet the planning requirements adopted in the PD. At the end of each two-year cycle, the CPUC will authorize procurement, where appropriate, that is necessary to occur within the next 1 – 3 years to meet the targets and needs identified in the IRP process. The first such procurement authorization, if needed, is anticipated to come toward the end of 2018, at the close of the first IRP cycle.

All LSE IRPs will be required to describe how they meet certain requirements for disadvantaged communities. The PD also sets a GHG emissions planning target of 42 million metric tons by 2030, which the CPUC is recommending the California Air Resources Board assign to the electricity sector as a whole.

The PD does not require early renewable procurement activities designed to capture the federal tax credits that are declining over the next few years, and instead opts for a steady approach to ongoing procurement of low-GHG resources over the planning horizon to 2030. The PD adopts a GHG planning price of $150 per metric ton of carbon dioxide equivalent in 2030, and directs its utilization as part of individual LSE IRP development, as well as its potential use as a GHG adder in evaluating the cost-effectiveness of distributed energy resources (DERs). The PD also lays out additional planning activities that the CPUC and its staff and consultants will undertake in this rulemaking in 2018, prior to the start of the next IRP cycle and in parallel with consideration of the individual LSE IRPs. The Proposed Decision is at:

A.16-08-006 (PG&E Diablo Canyon Closure & Proposed Procurement Plan)

On November 8, ALJ Allen issued a Proposed Decision that approves PG&E’s proposal to retire Diablo Canyon Nuclear Power Plant and approves $190.4 million in rate recovery: $171.8 million for employee retention and retraining, and $18.6 million for license renewal activities plus a portion of the cost of cancelled capital projects. The PD states that replacement procurement issues will be addressed in the IRP, and that rate recovery for the Community Impacts Mitigation Program is not approved because such a measure requires legislative authorization. Comments were due on November 29 and Reply Comments on December 4. See:

On November 28, all Commissioners except Martha Guzman-Aceves attended oral arguments in this proceeding. V. John White spoke on behalf of CEERT. On November 29, we and numerous other parties filed Comments. Our oral arguments and Opening Comments emphasized our disappointment with the PD, especially the fact that it defers all replacement procurement to the IRP and fails to commit to proposed GHG-free energy replacement for Diablo Canyon’s output. We requested that an Alternate Decision be issued. See:

CEERT filed Reply Comments on December 4 supporting multiple parties that cited errors in the PD that require correction through an Alternate PD. These errors include the PD’s failure to follow the law and apply the record on GHG emissions reductions; employee retention, community impacts, and license renewal cost settlements agreements; and contingency planning for the potential failure of an aging nuclear facility. See:

On December 6, CEERT’s V. John White, Sara Myers and James Caldwell, Jr. met with Commissioner Rechtschaffen’s Advisor Sandy Goldberg, and then with Commissioner Peterman’s Chief of Staff Jennifer Kalafut. In these meetings, John, Sara, and Jim expressed CEERT’s strong opposition to the PD, particularly for its rejection of any commitment to GHG-free energy to replace Diablo Canyon’s output. John, Sara, and Jim also stressed the need for a contingency plan in the event of an early shutdown of Diablo Canyon, and objected to the PD’s baseless deferral to the IRP proceeding of the key issues of replacing Diablo Canyon with GHG-free energy.

The PD was on the Agenda for the December 14 CPUC Business Meeting, but Commissioner Randolph held it until the January 11 meeting, without providing a reason for requesting this hold. An ex parte ban was in place on the PD from December 27 through January 11. The PD was adopted by all five Commissioners at the January 11 Meeting, with several of the Commissioners hailing this as a “landmark” decision on California’s move away from nuclear energy. The Commissioners also expressed confidence in Diablo Canyon replacement procurement decisions being handled in the IRP proceeding. The redlined revision of Final Decision D.18-01-022 is at:

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

On September 28, the CPUC approved an Order Instituting Rulemaking (OIR) to Oversee the RA Program, Consider Program Refinements, and Establish Annual Local and Flexible Procurement Obligations for the 2019 and 2020 Compliance Years. This proceeding will address changes to the RA program. See:

The OIR outlined a proposed schedule for the proceeding as follows:

October 30, 2017 Comments on OIR Due
November 9, 2017 Reply Comments on OIR Due
November 2017 Pre-Hearing Conference
December 2017 Scoping Memo
Q4 of 2017 Workshops
February 2018 Party Proposals filed
March 2018 Comments on Party Proposals
March 2018 Reply Comments on Party Proposals
March 16, 2018 CAISO publishes draft 2019 Local Capacity Requirement (LCR) and Flexible Capacity Requirement (FCR) Report
April 16, 2018 CAISO publishes final 2019 LCR and FCR Report
May 2018 Comments on 2019 LCR and FCR Reports due
May 2018 Proposed Decision
June 2018 Commission Decision

In Opening Comments on October 30, CEERT stressed the need for fundamental reflection about RA, not minor tweaking of what was thought to be a generally well-functioning program. Several fundamental issues of local and flexible procurement obligations must be determined before the CPUC asks for information about specific LCR and FCR needs for the 2019 – 2020 RA compliance years. CEERT believes overreliance on natural gas for reliability is the root cause of the serious issues encountered this year.

We recommended the following refinements to the RA program: (1) the transition away from near-exclusive reliance on gas-fired generation to supply RA must begin in this cycle; (2) the Moorpark Sub-Area should be a template for preferred-resource procurements to meet LCR needs; (3) flexible RA must be re-evaluated and redefined; and (4) LCR and FCR Studies (if any) must be transparent, timely and complete. See:

In our November 9 Reply Comments, CEERT observed that multiple parties argued for a thorough re-evaluation of the RA program. We stressed that the Commission must determine whether flexible RA should be eliminated or extensively modified. See:

On December 4, ALJ Allen held a Pre-Hearing Conference in the proceeding. Commissioner Randolph noted that in this rulemaking the CPUC would be tackling day-to-day RA work and larger, overarching issues with the RA program.

SCE, PG&E, and SDG&E Requests for Proposals (RFPs) or Requests for Offers (RFOs)

SCE Moorpark: In D.17-09-034, the CPUC rejected SCE’s 54 MW, 10-year gas-fired generation, 30-year refurbishment Ellwood contract and 0.5 MW energy storage contract (linked to the Ellwood contract) to meet need in the Santa Barbara/Goleta area. Instead, the Commission directed SCE to determine whether that need could be met in a manner more consistent with the CPUC’s goals of reduced reliance on fossil fuel, and told SCE to provide an update to the Energy Division Director and the Commissioners within six months of the Decision on efforts, actions, and resources under review to address needs in the Santa Barbara/Goleta area that may arise in the event of a loss of the two Goleta–Santa Clara 230 kV transmission lines. See:

In his concurrence, Commissioner Rechtschaffen agreed with the Decision’s conclusions, but noted he would have preferred that the Decision also address potential contingencies to best position SCE for a successful procurement of preferred resources in the larger area in the event that the California Energy Commission did not approve the 260 MW Puente gas plant.

On December 21, SCE submitted a plan to issue a Request for Proposals (RFPs) soliciting preferred resources and energy storage that would meet the local capacity requirement (LCR) needs in the Moorpark sub-area, and that “may also further resiliency objectives in the Santa Barbara/Goleta area.”

A November 30 Energy Division letter informed the parties in both the Moorpark Application and the IRP of SCE’s plan, and gave them an opportunity to submit informal comments. CEERT is reviewing SCE’s plan and intends to file such comments. This comment opportunity is different from prior LTPP/
LCR procurements when review of the plan was conducted by Energy Division only, with no opportunity for stakeholder input. CEERT hopes that this change will lead to a better RFP process to ensure procurement of preferred resources.

SCE Preferred Resources Pilot RFOs: Although SCE was eventually faced with terminating contracts that resulted from its first PRP RFO, it has continued to pursue approval of contracts signed pursuant to its PRP RFP 2, as detailed in A.16-11-002. SCE filed briefs in support of the 19 resulting contracts for 125 MW of preferred resources (Johanna A-Bank or Santiago A-Bank substations) in October 2017, which SCE states will meet DER and GHG emission-reduction goals. A Proposed Decision has not yet been issued, but no party contested these contracts.

PG&E Storage and Preferred Resources RFO: Though PG&E did not seek this authority by application or advice letter, on January 11 the CPUC signed out Resolution E-4909, which orders PG&E “to hold a competitive solicitation for energy storage and preferred resources (including renewables, demand response, and energy efficiency) to address two local sub-area capacity deficiencies and to manage voltage issues in another sub-area.”

This Resolution stems from a letter Calpine sent to CAISO in November 2016 to terminate Participating Generator Agreements for four peaking units, claiming these plants (and Metcalf Energy Center) “were no longer economic to operate at current energy and RA capacity prices,” and asking CAISO to study whether the plants were needed to ensure local reliability. In March 2017, CAISO determined that two of the peaking units (Yuba City and Feather River Energy Centers) were still needed to meet a local capacity need, and designated both as “must-run resources” (RMR). In November, CAISO determined the entire Metcalf Energy Center was needed for local reliability needs, and designated that unit as RMR. CAISO then filed three unexecuted RMR agreements for these plants with FERC on November 2.

In Resolution E-4909, however, the CPUC has found that, not only did these contracts conflict with CAISO’s policy since 2006 to reduce RMR agreements, but the “historical process for procurement of capacity for reliability” and the RA process had not been followed, which CAISO staff then acknowledged. The CPUC was also concerned about market distortions (i.e., from lack of competition for these RMR contracts) and adverse ratepayer impacts if the contracts were executed, and instead confirmed its own authority to direct procurement pursuant to PU Code Section 701, and to direct PG&E to take action to ensure the long-term reliability of California’s electric energy supply.

Citing the ability of energy storage and preferred energy resources to be fast-responding, reliable, and constructed in a short timeframe, and using the examples of SCE’s LCR RFOs, the Resolution authorizes PG&E to conduct one or more solicitations (described above) at its earliest opportunity. While parties such as CAISO, generators, and CCAs filed comments objecting to the Resolution, others, including PG&E, CESA, and environmental parties, filed comments in support. PG&E has 90 days from the issuance of the Resolution to launch the solicitations or submit a letter with justification for delay. Given the number of parties opposing the Resolution, it may be the subject of an application for rehearing, but no such application stays the effect of the Resolution or PG&E’s obligation to perform under it. The Resolution is at:

In September, PG&E filed a study request in the CAISO 2017-2018 Transmission Plan process, proposing to substitute preferred resources for its RMR contract with Dynegy for the Oakland C peaking plants. These peaking plants are the only utility-scale oil-fired generators in the state. The PG&E plan closely mirrors the SCE Moorpark RFP and Resolution E-4909. We expect a CAISO draft decision on the plan at the end of January and a final decision from the CAISO Board in March. Assuming CAISO agrees, PG&E will then file at the CPUC for a preferred-resource RFP that will allow cancellation of the RMR contract and retirement of the 40-year-old high-emission plants near Oakland’s Jack London Square.

SDG&E Preferred Resources RFO: On April 19, SDG&E filed an Application (A.17-04-017) for approval of contracts signed from its Preferred Resources LCR RFO. The Application asks for approval of 88 MW of new preferred resource contracts; however, like all of SDG&E’s recent procurements, it is extremely light on demand response and RPS-eligible resources, and consists of several battery storage installations and one AAEE contract. On January 4, the ALJ admitted into the record the prepared testimony that had been served on the application. No Proposed Decision has yet been issued.

Demand Response (DR)

CEERT is convinced that demand response is the key to decoupling gas-fired resources from their virtually exclusive position of supplying Local Capacity Requirements and other Resource Adequacy products. Unless we make significant progress on DR as a policy initiative, it will continue to be difficult to stop new gas development and to carry out an orderly retirement schedule for existing gas facilities. Therefore, CEERT continues to advocate vigorously before the CPUC to strengthen existing DR programs while pressing for changes in DR procurement, and to urge the CAISO Board of Governors and senior management to reduce barriers to expanded use of this crucial resource.

On September 15, ALJ Hymes and ALJ Atamturk issued a Proposed Decision (PD) in the DR Rulemaking, and on the same date, Commissioner Guzman-Aceves issued an Alternate Proposed Decision (APD). The decisions are identical on the adoption of steps to implement the Competitive Neutrality Cost Causation Principle and development of a framework for new models of DR. But the PD declines to approve an additional auction for the Demand Response Auction Mechanism (DRAM) pilot to be held in the spring for deliveries in 2019, whereas the APD orders SCE and SDG&E, and authorizes PG&E, to conduct an additional Pilot auction in 2018 for deliveries in 2019. The APD adopts a budget of $6 million for SCE, $1.5 million for SDG&E, and $6 million for PG&E should it elect to conduct the additional auction, and specifies the auction parameters and procurement criteria to be used for the additional auction.

At the October 26 Commission Business Meeting, all five Commissioners voted to adopt Commissioner Guzman-Aceves’ APD, which was issued as D. 17-10-017 on November 1. See:

DR Applications

On January 17, 2017, the IOUs filed Applications for Approval of their 2018 – 2022 DR Programs, which were consolidated into A.17-01-012, et al. by ALJ Ruling on February 16. On November 9, ALJs Hymes and Atamturk issued a Proposed Decision Adopting DR Activities and Budgets for 2018 – 2022. At the December 14 CPUC Business Meeting, the Commissioners voted to adopt the Proposed Decision as part of the Consent Agenda. Final Decision D.17-12-003 was issued on December 14.

D.17-12-003 adopts budgets for PG&E, SCE and SDG&E to conduct DR programs, pilots and associated activities for 2018 – 2022, and authorizes a budget of $334 million for PG&E, $751 million for SDG&E and $756 million for SCE. D.17-02-003 also finds that SDG&E has less than satisfactory cost-effectiveness ratios for its DR programs and portfolio, which necessitates closer oversight and monitoring. The decision directs SDG&E to reduce its administrative budget by 10% across all programs, meet with Energy Division quarterly to discuss progress in improving its cost-effectiveness, and file Tier 1 advice letters in January 2019 and 2020 on the costs of the previous year’s programs and cost-effectiveness analyses results. The decision also expresses support for the limited integration of DR and energy efficiency activities. See:

Other CPUC Rulemakings and Governance Actions

CEERT has had a limited budget to actively participate in other CPUC issues. Never-the-less, 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 September 25, Commissioner Peterman issued a Scoping Memo and Ruling in the PCIA proceeding (R.17-06-026). The category of this proceeding is ratesetting. The Scoping Memo can be found at:

The Scoping Memo states that the overall goal of this proceeding is for the CPUC to ensure that bundled retail customers of an electrical corporation shall not experience any cost increases as a result of either retail customers of an electrical corporation electing to receive service from other providers, or the implementation of a community choice aggregator (CCA) program. The CPUC shall also ensure that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load. The Scoping Memo identifies several Final Guiding Principles, and divides the proceeding into two tracks. Track 1 will deal with PCIA exemptions for CARE and Medical Baseline customers, and Track 2 will deal with evaluation and possible modification of PCIA methodology.

The schedule for the proceeding is as follows:
Track One

December 8, 2017 Opening Briefs on CARE and Medical Baseline PCIA Exemptions and Request for Evidentiary Hearings
January 12, 2018 Reply Briefs
January 26, 2018 If necessary, further procedural guidance
90 Days after Reply Briefs (if hearings are not held) Proposed Decision

Track Two

October 6, 2017 Meet and confer on data issues
No later than October 16, 2017 Workshop on “Review of Current Methodology”
No later than October 16, 2017 Joint filing of results of meet and confer on data issues
TBD Protective order adopted by ALJ Ruling
No later than November 17, 2017 Workshop on “Data-based Discussion of Cost Responsibilities and Going-Forward Solutions”
December 1, 2017 Joint status update on the need for evidentiary hearings
December 8, 2017 Ruling on schedule for testimony and hearings, if necessary
March 12, 2018 Testimony served and submitted
April 2, 2018 Rebuttal testimony served
April 16-20, 2018 (if necessary) Evidentiary Hearings
May 11, 2018 Opening Briefs due and request for oral argument
May 25, 2018 Reply Briefs due
July, 2018 Proposed Decision

On October 24, the CPUC held its first workshop in this proceeding. The workshop offered a review of the current PCIA methodology and gave parties an opportunity to establish a common frame of reference and answer questions about current methodology. On October 31, a second workshop was held on the evaluation of regulatory framework options for an evolving electricity market.

On November 22, Assigned Commissioner Peterman and ALJ Roscow issued a Ruling Confirming Scoping Memo Issues and Modifying Schedule in the PCIA proceeding. This Ruling directs parties to continue to meet and confer on data issues and file a Supplemental Joint Report no later than December 8. See:

On December 20, Commissioner Peterman and ALJ Roscow issued a Ruling that grants the relief sought by parties in their December 8 Supplemental Joint Report on Results of Meet and Confer Regarding Data Issues: the data-sharing proposal of the Supplemental Joint Report is approved; the proposed Modified Nondisclosure Agreement in the Supplemental Joint Report is approved; and the data aggregation approach for historical generation and pricing data in the Supplemental Joint Report is approved. See:

A two-day workshop on January 16 and 17 held a data-based discussion of cost responsibilities and “going forward” solutions.

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

CEERT has party status in this rulemaking, which has three concurrent tracks: Track 1 on methodological issues (quasi-legislative), Track 2 on demonstration and pilot projects (rate-setting), and Track 3 on policy issues (quasi-legislative). Track 1 will develop an integration capacity analysis (ICA) and locational net benefits analysis (LNBA). Track 2 will look at certain Demonstration Projects. Track 3 includes definition of the distribution services that can be provided by distributed energy resources (DERs).

At the September 28 CPUC Business Meeting, the Commissioners voted to adopt the Decision on Track 1 Demonstration Projects A (Integration Capacity Analysis) and B (Locational Net Benefits Analysis). Here is a link to Final Decision D.17-09-026, issued October 6:

On December 28, the CPUC issued a Proposed Decision on Track 3 Policy Issues, Sub-Track 1 (Growth Scenarios) and Sub-Track 3 (Distribution Investment and Deferral Process). Comments were filed December 28 and Reply Comments January 2. See:

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

As previously reported, on December 22, 2016, the CPUC issued D.16-12-036, a Decision Addressing Competitive Solicitation Framework and Utility Regulatory Incentive Pilot. While summer 2017 saw increased activity in this proceeding, there have been no new developments recently.

DER Action Plan

As with the IDER proceeding, there has been no recent activity with the DER Action Plan. The Final DER Action Plan was issued on May 3, and it is still unclear how this plan will be used going forward.

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

On October 2, Commission President Picker and ALJ Hymes issued a Scoping Memo in R.17-07-007 that divides this proceeding into three phases.

Phase 1 covers:

  • Urgent and/or Quickly Resolved Issues (Working Group One/Smart Inverter Working Group)
  • Integration Capacity Analysis and Streamlining Interconnection Issues (Working Group Two)
  • Planning, Construction and Billing of Distribution Upgrades Issues (Working Group Three)
  • Application Processing and Review Issues (Working Group Four)
  • Smart Inverter Issues and Coordination with Rulemaking R.14-10-003 (Working Group Five/Smart Inverter Working Group)
  • Safety and Environmental Issues (working Group Six)

Phase 2 covers:

  • Ratesetting Issues Requiring Coordination with R.14-08-013 (Working Group Seven)

Phase 3 covers:

  • Small and Multi-Jurisdictional Utility Rules (Working Group Eight)

Phases 1 and 3 are categorized as quasi-legislative and Phase 2 as ratesetting. Phase 1 will last until fall 2018 when a Proposed Decision on Proposals from Working Groups One and Two will be issued. Phase 2 will last from September 1, 2018 to summer 2019 when a Proposed Decision on Proposals from Working Groups Three through Six will be issued. Here is a link to the Scoping Memo:

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

At the September 28 CPUC Business Meeting, the Commissioners approved, as part of the Consent Agenda, the Decision Adopting Energy Efficiency Goals for 2018-2030. Final Decision D.17-09-025 can be found at:

This Decision adopts energy savings goals for ratepayer-funded EE program portfolios for 2018 and beyond based on assessment of economic potential using the Total Resource Cost test, the 2016 update to the Avoided Cost Calculator, and a GHG adder that reflects the CARB Cap-and-Trade Allowance Containment Reserve Price. This Decision defers adoption of cumulative goals until CPUC Staff can assess the viability of using a method for calculating savings persistence that the CEC will develop.

On November 14, the Commission issued D.17-11-006. This Decision: (1) directs the IOUs to discontinue the EE To-Code Pilots, for which the CPUC ordered program implementation plans in D.14-10-046; (2) directs the IOUs to work with other program administrators and third-party implementers to seek and report on to-code program research questions through their program design, implementation and evaluation activities; and (3) declines to require EE program administrators to employ Randomized Control Trial designs for specific programs. See:

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

On November 13, ALJ Fitch issued a Proposed Decision Addressing Third Party Solicitation Process for Energy Efficiency Programs. Comments were filed December 4 and Reply Comments December 11.

The PD approves a two-stage approach to soliciting third-party program design and implementation services as part of the EE portfolio. All IOUs will be required to conduct a Request for Abstract (RFA) solicitation, followed by a full Request for Proposal (RFP) stage. The PD also approves the general schedule and sequencing of solicitations over the next several years as the IOUs move toward having third-party providers design and implement a greater share of their EE portfolios.

The IOUs must continue to use procurement review groups for design and conduct of solicitations, but do not have to adopt an Independent Evaluator structure analogous to the structure used in supply-side solicitations. Instead, the IOUs will be required to submit a short list of selected third-party contracts after the RFA is completed, along with a proposed RFP, for formal CPUC staff review via a Tier 2 advice letter. Final contract awards will be the responsibility of the IOUs. The Commission also requires a set of standard contract terms and conditions to be developed and reviewed prior to the conduct of any solicitations. See:

The PD was adopted at the January 11 CPUC Business Meeting.

Energy Storage (R.15-03-011)

The only remaining issue in this proceeding pertains to Multiple Use Applications (MUAs). On November 3, the CPUC issued a Proposed Decision that provides direction to the utilities on how to promote the ability of storage resources to realize their full economic value when they are capable of providing multiple benefits and services to the electricity system. The PD adopts 12 rules to govern evaluation of energy storage MUAs, along with definitions of service domains, reliability services and non-reliability services. The PD also closes the proceeding.

At the December 14 CPUC Business Meeting, Commissioner Peterman asked to discuss and hold the PD to the January 11 Meeting because she wanted to further examine Rules 6 and 7 to find a balance between being too permissive and excluding use cases that might be needed in 2018. Rule 6 currently states that a single storage resource may not contract for two or more different reliability services from the same capacity in a single or multiple domains over the same or overlapping time interval for which the resource is committed to perform or be available. Rule 7 provides that the exception to Rule 6 is for RA services. See: The PD was adopted at the January 11 Business Meeting as Final Decision D.18-01-003.

Time-Of-Use (TOU) Rates (R.15-12-012)

At the October 26 CPUC Business Meeting all five Commissioners voted to adopt D.17-10-018, modifying D.17-01-006, which adopted a framework, including guiding principles, for designing, implementing and modifying the time intervals reflected in TOU rates for each of the three IOUs. D.17-10-018 modifies D.17-01-006 to extend the interconnection-on-file date to 60 days following the issuance of D.17-10-018 for public schools and other public agency customers. It also eliminates the requirement for the IOUs that construction of projects eligible for grandfathering be completed by a date certain (previously July 31, 2017). See:

Water-Energy Nexus (R.13-12-011)

At the December 14 CPUC Business Meeting, the Commissioners adopted a Proposed Decision Resolving Petition for Modification of D.16-12-047, Adopting the Plan of Action, and Closing Rulemaking in the Water-Energy Nexus proceeding (R.13-12-011). See:

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

CEERT is tracking this proceeding because of its potential significance for document access at the CPUC. At the September 28 CPUC Business Meeting, all five Commissioners voted to adopt the Phase 2A Decision Adopting General Order 66-D and Administrative Processes for Submission and Release of Potentially Confidential Information. This Decision updates processes for submission of information to the CPUC with a claim of confidentiality, requests for information pursuant to the California Public Record Act, Commission determination of confidentiality, and public disclosure of non-confidential information. See:

On October 16, ALJ Lirag issued a Ruling Allowing Comments to Parties’ Proposed Confidential Matrices. Comments on the proposed confidential matrices submitted by various working groups were filed on October 30. See: