By Erik Takayesu, PE Director, Electric System Planning Southern California Edison More Than Smart Webinar August 4, 2015 Distribution Resources Plan

Erik Takayesu is the Director of Electric System Planning for Southern California Edison. The organizations he currently oversees include Grid Modernization, Distribution and Transmission System Planning and Engineering, Distribution Automation, Power Quality, Generation Interconnection Planning and Studies. He has held various roles at SCE, including managing Grid Operations, Reliability Engineering, and Asset Management. As part of modernizing the electric grid, Erik has been instrumental in leading the efforts to develop SCE’s Distribution Resource Plan. His organization is also developing the strategy for enabling the electric grid to integrate Distributed Energy Resources. Erik has a bachelor’s degree in Electrical Engineering from the California State University at Long Beach, is a licensed PE, and holds his master’s degree in Organizational Leadership from Gonzaga University. 1 Erik Takayesu, PE Director Electric System Planning Southern California Edison

Overview I.Assembly Bill 327 and PUC Code Section 769 II.General Structure of the DRP III.Analysis, Methodologies, and Demonstration Projects IV.Conclusion 2

California’s Distribution Resource Plan (DRP)  AB 327 (2013) requires utilities to submit a Distribution Resources Plan (DRP) proposal by July 1, 2015  Identifies optimal locations for distributed energy resources (DERs)  Establishes Section 769 that acknowledges the need for investment to integrate cost- effective DERs  Requires unified methodology for determining circuit integration capacity and net benefits methodology  Recognizes need to revise tariffs and incentives to promote DER in locations that provide the greatest net benefits to the grid  Provides for discussion on safety benefits, barriers to deployment, and integration with existing Commission approved programs and coordination with the General Rate Case  The Final Guidance Document for Section 769 issued February 6, 2015  Described as “New Framework for Distribution Planning”  Intended to move IOUs towards seamless integration of DERs  Outlined requirements for analysis, methodologies, and demonstration projects  Based on More than Smart: A Framework to make the Distribution Grid More Open, Efficient and Resilient 3

Guidance for Public Utilities Code Section 769: A New Framework for Distribution Planning Supporting California’s 2030 and 2050 GHG reduction targets Beginning the process of moving towards full integration of DERs in distribution system planning, operations, and investments Modernizing the electric distribution system to accommodate two-way flows of energy and energy services throughout the IOUs’ networks Enabling customer choice of new technologies and services that reduce emissions and improve reliability in a cost efficient manner Animating opportunities for DERs to realize benefits through the provision of grid services Creating a “plug-and-play” distribution grid for DERs 4

General Structure of DRPs 1 Overview and Policy Support 2 ICA, Locational Value, Demonstration & Deployment 3 Data Access Executive Summary Policy Goals Integration Capacity Analysis Locational Value Analysis Demonstration & Deployment Data Access Policies Proposed policies and procedures for sharing utility and third party data Opportunities and limitations 4 Tariffs and Contracts 5 Safety Considerations 6 Barriers to Deployment 7 Coordination w/ Capital Investment Plan, GRC & Phasing of Next Steps Existing tariffs Recommendations for incorporating locational value and demonstration projects Interconnection Policies Safety/reliability standards Major considerations for DER owners/operators Outreach activities Regulatory, safety and grid insight barriers Proposed solutions to barriers including technology development and deployment Utility and CEC forecasting High-level Capital Coordination with GRC Phasing of Next Steps

6 Key Takeaways: 1. The higher the distribution voltage, the higher the potential integration capacity. For example, the chart above shows that the 12kV line segments have more hosting capacity than the 4kV line segments. 2. The closer the line segment is to the substation, the more DERs it can accommodate. In the above chart, Line Segment 1 is closest to the substation. Integration Capacity Analysis To determine the hosting capacity available for DERs, each utility: Evaluated each circuit’s DER hosting capacity by considering thermal ratings, protection system limits, and power quality standards to meet safety standards ICA analysis performed by line section, between 3 – 4 segments per circuit Displayed results via online maps

Locational Net Benefits Methodology (LNBM) 7 The unified methodology is to be based on the Commission- approved E3 Cost-Effectiveness Calculator, but enhanced to include location-specific values Objective is to identify optimal locations where DERs could provide a high benefit value Avoided sub-transmission, substation, and feeder-level CapEx and O&M related to forecasted load growth Avoided CapEx and O&M related to ensuring distribution voltage and power quality Avoided CapEx and O&M related to maintaining/enhancing distribution reliability and resiliency Avoided system and local-area transmission CapEx and O&M Avoided flexible RA and renewables integration expenditures Avoided societal costs and avoided public safety costs linked to the deployment of DERs

8 DER Growth Scenarios “[T]he Utilities shall develop three 10-year scenarios that project expected growth of DERs through 2025, including expected geographic dispersion at the distribution feeder level and impacts on planning” Scenario 1: IEPR Trajectory Case Intended to reflect a modest base scenario for California’s resource and infrastructure planning. Reflects a “modestly conservative future world with little change from existing procurement policies” and “business as usual practices”. Scenario 2: IEPR High Growth Case This scenario “diverges from the Trajectory scenario by assuming a high incremental amount of demand-side small PV and a low incremental amount of demand-side CHP”. Scenario 3: Very High Growth Case Provides that such goals include: Governor’s 2030 Energy Policy, Zero Net Energy, 2030 GHG reductions, Governor’s Zero Emission Vehicle Action Plan, Commission’s 2020 Energy Storage Requirements, Commission’s Demand Response (DR) Goal of 5% of peak load managed by DR, and Reliability Improvement

Demonstrate Projects Five Demonstration Projects A.Demonstrate Integrated Capacity Analysis B.Optimal Locational Benefit Analysis C.Field Demonstration of DER Locational Benefits D.Distribution Operations at High Penetrations of DERs E.Demonstrate DER Dispatch to Meet Reliability Needs (a.k.a., microgrid) 9

Conclusion DRPs represent an important step towards embracing and implementing the Commission’s DRP vision and meeting changing customer expectations Utilities will incorporate DRPs into their distribution system planning and operations to meet current and future DRP goals DRPs will support the facilitation of DER development and encourage customer value creation, including robust recommendations to overcome barriers to DER deployment The DRPs will help to enable a fully integrated, low-carbon electricity system, and it is clear that utility grid modernization investments must keep pace with DER technology innovation 10