1. Locational Net Benefit Analysis Working Group June 9, 2016 1 pm – 3:30 pm CPUC Golden Gate Room, San Francisco drpwg.org

2. Agenda 2 TimeTopicPurpose 1:00 – 1:20Introductions & OverviewIntroductions Purpose of Meeting Proposed schedule for WG participation 1:20 – 2:00Review Draft Outlines of LNBA Implementation Plans: Methodology Overview of IOU plans Questions for WG Participants 2:00 – 2:20Presentation by E3 on LNBA workDiscussion around E3 role in assisting IOU’s with LNBA study 2:20 – 2:45Draft Implementation Plans: Demo B DPA(s)Pilot project locations 2:45 – 2:55Break 2:55 – 3:10Next Steps & Questions regarding LNBA plansDiscuss next steps for IOU’s and WG 3:10 – 3:25Proposed Calendar for addressing data issues in WG meetings Brief review of DRP data issues to date Proposed schedule for addressing data 3:25 – 3:30Next stepsOutline of next steps for WG

3. LNBA WG PURPOSE - Pursuant to the May 2, 2016, Assigned Commissioner’s Ruling (ACR) in DRP proceeding (R.14-08-013), the Joint Utilities are required to convene the LNBA WG to: 1.Monitor and Support Demonstration Project B 2.Improve and refine LNBA methodology 3.Coordinate with IDER Cost Effectiveness WG on system-level valuation activities 4.Coordinate with IDER Competitive Solicitation Framework WG where objectives overlap (e.g. description of grid deficiencies and performance requirements) CPUC Energy Division role Oversight to ensure balance and achievement of State objective Coordination with both related CPUC activities and activities in other agencies (CEC, CAISO) Steward WG agreements into CPUC decisions when necessary More Than Smart role Engaged by Joint Utilities to facilitate both the ICA & LBNA working groups. This leverages the previous work of MTS facilitating stakeholder discussions on ICA and LBNA topics. 3 LNBA Working Group Background

4. May 2 nd, 2016 - Assigned Commissioner Ruling on ICA and LNBA May 12 th, 2016 – First Joint Utility meeting on ICA and LNBA June 1, 2016 – First in person meeting to get input on Joint Utility Implementation plans; June 9, 2016 (today) – In person meeting to discuss LNBA Plans June 16, 2016 –Utilities file LNBA implementation plans to CPUC July, 2016 – Q2, 2017 – Monthly LNBA WG meetings re/LNBA implementation Q4, 2016 – Final Demo B report due Q4, 2016 – Long-term LNBA refinement intermediate status report due Q2, 2017 – Utilities submit Long-term LNBA refinement final report 3 DRAFT LNBA Working Group Schedule

5. Short Term: May 2 nd –end of Q4 2016 “Recommend a format for the LNBA maps to be consistent and readable to all California stakeholders across the utilities’ service territories with similar data and visual aspects” “Consult to the IOUs on further definition of grid service, and in coordination with the IDER proceeding” Long Term: May 2 nd -end of Q2 2017 “Continue advancement and improvement of LNBA methodology, consulting to IOUs on: Methods for evaluating location-specific benefits over a long-term horizon that matches with the offer duration of the project Methods for valuing location-specific grid services provided by advanced smart inverter capabilities Consideration/development of alternatives to the avoided cost method (ex: distribution marginal cost method, etc.) IOUs shall determine a method for evaluating the effect on avoided cost of DER working “in concert” in the same electrical footprint of a substation” 3 ICA WG Schedule - May 2 nd CPUC ruling

6. 3 Proposed schedule for LNBA WG topics Proposed WG Discussion Topics JuneLNBA Plans submitted to CPUC June 16 th JulyLNB Methodology: Deep Dive and final DPA selections AugustReview Demo Project B and data on upgrade projects SeptemberUpdate on Pilot Projects OctoberLNB Maps: Discussion on Output Format November LNB Methodology: Calculated LNBs from Pilot Projects and Development of DER Requirements December Report Submitted/ LNB Maps: Lessons Learned and Future Refinements Q4: 2016 FINAL LNBA REPORT DUE INTERMEDIATE METHODOLOGY REFINEMENT REPORT DUE Q2: 2017FINAL METHODOLOGY REFINEMENT REPORT DUE

7. 3 LNBA Working Group Participation How will the Working Group provide ongoing input into Demo Project B development and LNBA methodology? IOU ongoing solicitation and incorporation of feedback Stakeholder submitted comments Consensus recommendations to CPUC How should Working Group participants continue to stay engaged between monthly meetings? Do you have comments/suggestions on proposed schedule of monthly LNBA WG topics for discussion? Today’s attendance list will be available online at http://www.drpwg.orghttp://www.drpwg.org

8. Draft Methodology

9. LNBA Specific Requirements (4.4.1) The LNBA analysis methodology will identify the full range of applicable electric services and quantify Distributed Energy Resource (DER) capabilities to provide such services in place of upgrade projects. The method will utilize a three stage process for identifying and qualifying the services as part of the upgrade projects 9

10. Implementation Plan Methodology (4.4.1 (A) ) The IOUs will identify the full range of electric services that will result in avoided cost for all locations within DPA. The list will include any and all electrical services associated with distribution grid upgrades in three categories of: Utility distribution planning projects Circuit reliability/resiliency improvement projects Maintenance projects IOUs will consult with their groups responsible for distribution planning, distribution reliability, and asset management and maintenance organizations to identify capital upgrade projects, SCADA upgrade projects and cable and equipment replacement projects In addition, IOUs will leverage industry experience in this area based on the work done by utilities in other states with high penetration levels of PV, such as Hawaiian Electric, Pepco Holdings Inc., Duke Energy, Eversource, etc. 10

11. Implementation Plan Methodology (4.4.1 (B) i, ii, iii) To assess the value of a service through DER, a comprehensive list of locations and project types will be prepared as applicable in three project areas of: capital upgrade projects, circuit reliability enhancement projects, and/or maintenance projects. The timeframe of interest to identify projects covers three horizons: Near term forecast (1.5-3 years), Intermediate term (3-5 years), Long term (5-10 years) and Ultra-long-term forecast that extends beyond 10-year horizon (to the extent such dates that are manageable by the analysis tools). 11

12. Implementation Plan Methodology (4.4.1 (B) i, ii, iii) A six-step approach is suggested to address the entire process of project selection, project cost estimation, service qualification and cost calculations for the qualified services. 12

13. Implementation Plan Methodology (4.4.1 (B) iv, v, vi) The following key features and questions will be addressed in characterizing each service: A detailed description of the service How is the service provided today? What are the requirements for the service? How does location impact the service? How would DER provide this service? What is the value of the service today? Example calculation of the value Justification for a zero value, i.e., if DER provides no value or it has a negative impact What changes would be required for DER to provide this service, if applicable? 13

14. Implementation Plan Methodology (4.4.1 (B) iv, v, vi) 14

15. Draft Gantt Chart for LNBA 15

16. Draft Gantt Chart for LNBA (cont’d) 16

17. E3 17

18. Energy and Environmental Economics, Inc Avoided Cost Experience Utility marginal costs across North America for over 30 years Stanford doctoral dissertation on area- and time-specific avoided costs 2004 methodology for CPUC EE evaluation 2016 avoided cost update California building energy standards Originated the field of Local Integrated Resource Planning studies Kerman PV study Delta study ConEd iDSM program (2014 Innovation Award winner from Utility Analytics Institute) 18

19. E3 Public Tools Sample E3 Public Tools for the CPUC DERAC and ACM avoided cost models E3 Calculator Demand response template RPS Calculator RECAP model NEM Public Tool E3 Role in LNBA: Create a Demo B public tool that: Is common to all IOUs Incorporates system values from DERAC/ACM tools Develops avoided costs for local T&D Evaluates the avoided costs for representative DER technologies 19

20. SDG&E Demo B Area 20

21. SDG&E DPA Selection – Northeast San Diego 231,000 Customers 200,000 Res 30,000 Comm 129 Ind 1000 MW Peak 40 Substations 158 12kV Circuits 20 4kV Circuits 47,000 Transformers 21

22. SCE Demo B Area 22

23. SCE Demo B Planning Area Selection SCE intends to select one common DPA for both Demo A and Demo B Demo B requires the DPA(s) to contain, at a minimum: One near-term and one longer term deferral opportunity One capacity-related and one voltage support/power quality or reliability/resiliency-related deferral opportunity 23

24. SCE Demo B Description (tentative) Rural DPA Substations4 AreaCentral Valley Service Area120 Square Miles Feeders49 Customers49,700 2016 Projected Load314 MVA Load TypeMixture of Residential and Commercial, with Significant Agricultural Service Transformers9,617 NotesLoad Growth Driven by Drought

25. PG&E Demo B Areas 25

26. PG&E Demo B DPA Description (tentative) 26 Chowchilla DPA LocationMadera County (Rural) Substations4 Feeders20 (all 12 kV) Customers13,000 Recent Historical Peak155 MW Customer Type~60% Residential/ 30% Agricultural / 10% Commercial & Industrial

27. PG&E Demo B DPA Description (tentative) 27 Chico DPA LocationButte County (Urban/Suburban) Substations10 Feeders37 12 kV; 4 4 kV Customers57,000 Recent Historical Peak235 MW Customer Type~80% Residential/ 5% Agricultural / 15% Commercial & Industrial

28. 3 DRP Data Overview

29. 3 Data needs for statutory compliance 769(a) [Applies to] distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies. 769(b) [DRP's shall] identify optimal locations for the deployment of distributed resources [by evaluating] locational benefits and costs of distributed resources [...] based on reductions or increases in local generation capacity needs, avoided or increased investments in distribution infrastructure, safety benefits, reliability benefits, and any other savings [...] to ratepayers [...]. 769(c) The commission shall review each distribution resources plan proposal submitted by an electrical corporation and approve, or modify and approve, a distribution resources plan for the corporation. The commission may modify any plan as appropriate to minimize overall system costs and maximize ratepayer benefit from investments in distributed resources. 769(d) Any electrical corporation spending on distribution infrastructure necessary to accomplish the distribution resources plan shall be proposed and considered as part of the next general rate case for the corporation. The commission may approve proposed spending if it concludes that ratepayers would realize net benefits and the associated costs are just and reasonable. The commission may also adopt criteria, benchmarks, and accountability mechanisms to evaluate the success of any investment authorized pursuant to a distribution resources plan.

30. 3 Data needs for DRP market transactions applies to all distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies. Identifies optimal locations for the deployment of distributed resources by evaluating locational benefits and costs of distributed resources based on reductions or increases in local generation capacity needs, avoided or increased investments in distribution infrastructure, safety benefits, reliability benefits, and any other savings to ratepayers. Clear visibility into an individual project’s ability to realize net benefits. The ability to propose criteria, benchmarks, and accountability mechanisms to evaluate the success of any investment authorized pursuant to a distribution resources plan to the Commission.

31. 3 Data needs to improve DER integration From utilities: identification of proposed methodologies’ limitations Foundation for broader conversation on best practices Blue sky for “perfect data” Survey of alternatives from other markets Initial assessment of market solutions for increased data integration From market participants: Neutral as to type of technology solution Full spectrum of possible data for improving DER integration Market mechanisms for data from other jurisdictions

32. 3 Data needs - next steps Ongoing stakeholder coordination on data needs (working groups, draft filings) July MTS working paper on data needs Proposed path to operationalization of data requirements

33. 3 Next steps