Meeting Notes

DRP Working Group

LNBA Subgroup on Avoided Transmission

webinar

July 19, 2017

DRAFT

These notes summarize the LNBA working group (WG) webinar facilitated by More Than Smart. For a stakeholder list and presentations for this meeting (and for previous meetings), go to or contact Laura Wang at for more information.

Agenda

  1. Introduction, Proposed Schedule, Process
  2. ACR Guidance and Subgroup Objectives
  3. Current transmission value in DERAC
  4. Overview of CAISO transmission planning process
  5. Q&A, next steps

Meeting Summary

  • Summary: The objectives of the July 19 call were to kick off the subgroup, establish processes and procedures, review the objectives of this group over the next six months, review reporting requirements, and do an overview of both the current DERAC method of calculating avoided transmission value and the CAISO transmission planning process.
  • Agenda Item A: MTS reviewed the subgroup communications and meeting process. Bi-weekly hour calls are proposed on Wednesdays, 12pm-1pm. All meeting materials will be posted on drpwg.org.
  • Agenda Item B: Marc Monbouquette (CPUC) presented on the June 7 ACR and set objectives for the subgroup moving forward. Determining a non-zero avoided transmission value is identified as a Group I priority item for the LNBA Working Group. The ACR directs the LNBA WG to form a technical subgroup to develop methodologies for non-zero location-specific transmission costs. An interim status report is due on this topic on August 31, along with the other LNBA Group I items. The final recommendations of this group will be included in the Final WG report due January 7, 2018. This subgroup will use the same documentation strategy as proposed for the wider LNBA Working Group.

The objectives of this group are set out as follows:

1)Understand how the CAISO transmission planning process determines transmission needs, assesses uncertainty and sensitivities, and approves projects

2)Understand how IOUs calculate marginal transmission costs in GRC Phase 2

3)Examine methods to introduce locational granularity into avoided transmission costs for LBNA (and DERAC)

4)Examine how to incorporate system-level avoided transmission values (as proposed by stakeholders)

The Energy Division also noted that the Energy Division expects that the LNBA will be able to calculate a value which reflects location-specific avoided transmission costs, and that the Energy Division is prepared to develop a default straw proposal if needed. This proposed straw methodology would be calculated either using 1) load growth-related transmission line sections identified in TPP, or 2) deferrable transmission projects identified by method PG&E employs in GRC Phase 2 testimony.

  • Agenda Item C: Larsen Plano (PG&E) discussed how avoided transmission value is currently calculated in the DERAC methodology used for Demo B. For every IOU, within GRC Phase 2, each develops a marginal transmission and distribution value that is used to allocate the revenue requirement. This is the same information used in the DERAC model. This marginal cost is provided for different territory divisions and mapped to different climate zones within the utility’s territory. E3 then takes weather data to determine a climate zone-specific load shape. The t&d marginal costs are then mapped to climate zones, and allocated across peak hours. The process is described in full here. This is primarily used for AAEE and DR cost-effectiveness analysis. As this cost is still quite aggregated, this subgroup is meant to develop a more granular methodology, from a locational perspective.
  • Agenda Item D: Jeff Billinton (CAISO) presented an overview of the CAISO transmission process.
  • Three phases of the TPP: Phase 1 focuses on the development of the unified planning assumptions and draft study plan. This includes stakeholder input around assumptions, and results in a finalized study plan in March. Phase 2 focuses on conducting further analyses to develop a transmission plan, which is taken to the ISO Board for approval in March. In August 15, stakeholder meetings begin based on study results to identify existing or potential mitigation. In September, reliability results are presented and potential mitigation options are discussed. If it is a transmission mitigation option, the ISO Board is required to approve it. If the issue is mitigated using preferred resources, the ISO does not have the ability to approve the procurement of those, and instead just monitor the procurement – if the resources didn’t materialize, the CAISO would need to look at alternative mitigation. IOUs also present potential alternative mitigation options. There is a two month comment period for parties to submit alternative considerations. These include both wires solutions as well as non-wires solutions. Finally in Phase 3, projects over a certain size and dollar value are put out for competitive solicitation.
  • Coordination of assumptions: CAISO coordinates with the CEC IEPR process for demand-side assumptions, and the CPUC on supply-side assumptions. Additional localized weather studies may be included. For the 2017-2018 TPP, the CEC’s Energy Demand Updated Forecast (2017-2027) is being used.This includes the updated Peak-Shift Scenario Analysis from the CEC. It is mentioned that the CEC is moving towards using an 8760-hour load forecast (moving away from using historic peaks for forecasting).
  • DER has become more embedded in installed capacity forecasts. The CEC has started modeling both gross load and DER in both power flow and stability models.

Stakeholders asked a number of questions during the Q&A.

  • Clean Coalition clarified that the purpose of the LNBA WG is to determine the value of avoiding transmission – this could include both an avoided cost for identified transmission needs, as well as a value for when DERs can avoid an unidentified need, or where the transmission planning process has not identified a project to begin with, due to DER.
  • CPUC asked for additional details on how CAISO conducts sensitivity analysis, and whether taking the sensitivity analysis and extrapolating out DER impacts would be a good starting point for methodology development. It was explained that sensitivity studies are conducted on the base scenario analysis during the study plan and is included in the August results. Those sensitivity studies include evaluating PV speak shift, what happens if projected AAEE doesn’t materialize, etc. These results are detailed in Chapter 7 of the TPP, as well as Appendix B for individual planning areas. CAISO only identifies mitigation needs on the base scenario. CAISO estimates that it would take significant amount of work to extrapolate out DER within sensitivity analyses for projects, as those values are embedded within the IEPR. Mitigation determination is not conducted at the sensitivity level. So, the CAISO would need to conduct a completely separate sensitivity analysis and cost analysis at the mitigation level.
  • The CPUC asked for additional clarification on how CAISO evaluates non-wires alternatives, and for historic examples to illustrate. SONGS mitigation was a mix of preferred resources, transmission projects, and conventional generation. CAISO also gave an example of recent aging Oakland infrastructure. The mitigation analysis for Oakland included several possible options, including repowering gas generation, two transmission options (one at a lower 230kv voltage), and considering preferred resources. The identified preferred alternative was a mix of transmission components and preferred resources, and will continue to be evaluated at this September’s stakeholder meeting.
  • SEIA asked how much cost detail is included in the TPP. The TPP is a 10-year plan. Transmission costs are detailed using submitted cost figures. Non-wires costs are still being determined. Preferred resource costs are determined by submitted cost figures during mitigation analysis, and compared to wires solutions.
  • Tesla asked for additional clarity on solicitation of preferred resources, and asked about possible coordination with the transmission access charge work at CAISO. It was clarified that the preferred resources solicitation is done through CAISO rather than CPUC, and that the CAISO evaluates the local capacity requirement and transmission planning area to identify the exact solicitation (e.g., preferred vs. conventional, etc.). CAISO expressed that their transmission access charge stakeholder process, which is looking at the avoided transmission cost of DERs, should be separate processes.