1. LNBA Subgroup: Avoided Transmission Value
July 19, 2017
Webinar
drpwg.org

2. Time
Topic
12:00-12:05
Introduction, Proposed Schedule, Process
12:05 – 12:15
ACR Guidance and Subgroup Objectives
12:15 – 12:30
Current transmission value in DERAC
12:30 – 12:50
Overview of CAISO Transmission Planning Process
12:50 – 1:00
Q&A and Next Steps

3. LNBA Working Group Background: June 7 ACR
June 7 ACR: Overview
The ACR sets scope and schedule, pre-Working Group deliverables, and status report and final reporting milestones for continued long-term refinement discussions pertaining to the ICA and LNBA in Track 1 of the DRP proceeding.
The ACR scopes and prioritizes LNBA long-term refinement items as identified in the Final Working Group Report and the Interim Long-Term Refinement Report.

4. LNBA Working Group Background: June 7 ACR
Reports are due as follows:
Interim status report: Group I: August 31, 2017
Interim status report Group II, III: October 31, 2017
Final report: January 7, 2018
Proposed Schedule for LNBA Subgroup:
Bi-weekly hour calls or webinars on alternating Wednesdays, 12pm-1pm
MTS will circulate notes in the following days
All proposals can be circulated to the group; MTS will host all circulated documents on the DRPWG website:

5. Marc Monbouquette California Public Utilities Commission July 19, 2017
LNBA Avoided Transmission Subgroup – ACR Guidance + Subgroup Objectives
Marc Monbouquette
California Public Utilities Commission
July 19, 2017

6. LNBA LTR Scope in June 7 ACR
Group I, Item 5: Form technical subgroup to develop methodologies for non-zero location-specific transmission costs
Later on this call: discuss expanding scope to consider system-level avoided transmission values
Interim Status Report (≤ 1 page) on this topic due August 31
Recommendations included in final WG report due January 7, 2018
Employ same documentation strategy as for other scoped topics

7. Objectives
Understand how CAISO TPP determines transmission needs, assesses uncertainty and sensitivities, and approves projects
Understand how IOUs calculate marginal transmission costs in GRC Phase 2
Currently the basis for T&D values in DERAC
Examine methods to introduce locational granularity into avoided transmission costs for LNBA (and DERAC)
Examine how to incorporate system-level avoided transmission values (as proposed by stakeholders)
Current DERAC avoided T&D values based on marginal costs adopted in GRC Phase 2

8. ED default straw proposal
Calculate marginal transmission costs for distribution system areas that would be served by either
Load growth-related transmission line sections identified in TPP
Deferrable transmission projects identified by method PG&E employs in GRC Phase 2 testimony
 Bottom line: we expect LNBA calculation to reflect location-specific avoided transmission costs; ED will develop default proposal if needed

9. Transmission Planning with DER
J.E.(Jeff) Billinton
Manager, Regional Transmission - North
July 19, 2017

10. Transmission System
500 kV
230 kV
115 kV
60 / 70 kV

11. The ISO’s transmission planning process
Four Consultation Windows
April Year X
March Year X+1
October Year X+1
ISO board approval of transmission plan
Phase 1
Development of ISO unified planning assumptions and study plan
Incorporates State and Federal policy requirements and directives
Demand forecasts, energy efficiency, demand response
Renewable and conventional generation additions and retirements
Input from stakeholders
Ongoing stakeholder meetings
Phase 2
Technical Studies and Board Approval
Reliability analysis
Renewable delivery analysis
Economic analysis
Publish comprehensive transmission plan
ISO Board approval
Phase 3
Competitive Solicitation Process
Receive proposals to build identified reliability, policy and economic transmission projects
Evaluate proposals to meet qualification for consideration
Take necessary steps to determine Approved Project Sponsor(s)
Continued regional and sub-regional coordination

12. Coordination of Assumptions
CEC IEPR Energy Demand Forecast
Input for Demand side assumptions
Includes the consumption load and the load modifiers (behind the meter distributed generation, demand response, electric vehicles, committed energy efficiency and the additional achievable energy efficiency, are included in the forecasts as a baseline assumption
CPUC Assumptions and Scenarios
Input of Supply side assumptions
Includes assumptions of renewable portfolios, conventional generation, storage and demand response

13. Load Forecast Assumptions for 2017-2018 TPP Energy and Demand Forecast
California Energy Demand Updated Forecast adopted by California Energy Commission (CEC) on January 25, 2017 is being used.
The following are how load forecasts are used for each of the reliability assessment studies.
1-in-10 weather year, mid demand baseline case with low AAEE load forecasts will be used in PG&E, SCE, SDG&E, and VEA local area studies including the studies for the local capacity requirement (LCR) areas
1-in-5 weather year, mid demand baseline case with mid AAEE load forecast will be used for bulk system studies

14. Load Forecast Assumptions Peak-Shift
The California Energy Demand Updated Forecast includes Peak-Shift Scenario Analysis and states the following with respect to the use results of this analysis in the ISO TPP studies:
“The results of the final adjusted managed peak scenario analysis can be used by the California ISO in TPP studies to review previously -approved projects or procurement of existing resource adequacy resources to maintain local reliability but should not be used in identifying new needs triggering new transmission projects, given the preliminary analysis. More complete analyses will be developed for IEPR forecasts once full hourly load forecasting models are developed.”
In the TPP, the ISO is using the CEC energy and demand forecast for the base scenario analysis

15. Forecast of Installed Capacity of Self Generation
Chart developed from Table of ISO TPP Study Plan

16. Modeling of Load and Load Modifiers Top Down – Bottom Up Approach
CEC IEPR Energy and Demand Forecast
At System Level
Alignment of assumptions between:
CEC IEPR
CPUC IRP
Utilities Distribution Planning and DRP
ISO Transmission Planning Process
Utilities Distribution Planning
Allocation at ISO Controlled Grid Transmission – Distribution Interface

17. Questions!