1. 1 Integrated Capacity Analysis Working Group July 25, 2016 OAKSTOP, Oakland, CA drpwg.org

2. 2 Agenda TimeTopic 9:00-9:15Introductions 9:15–10:15Use Case Discussion Indicative Maps Planning Interconnection 10:15-11:45Discussion of Stakeholder Comments 11:45-12:30Lunch 12:30 –1:45Data and Maps 1:45-3:15Portfolio Analysis 3:15 – 3:30Summary & Next Steps

3. 3 ICA Working Group Background ICA 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 ICA WG to: 1.Refine Integration Capacity Analysis Methodologies and Requirements 2.Authorize Demonstration Project A 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.

4. 4 ICA Working Group Schedule to Date May 2 nd, 2016 - Assigned Commissioner Ruling on ICA May 12 th, 2016 – First Joint Utility meeting on ICA and LNBA May 18 th, 2016 – Joint Utility meeting seeking input on (1) use of abstraction analysis or power flow analysis, and (2) level of granularity desired June 1, 2016 – First in person meeting to get input on: proposed Joint WG Recommendation for Demonstration A; input into ICA Implementation plans; discuss Comparative Analysis June 9, 2016 – In person meeting to discuss ICA Plans before submittal June 16, 2016 – Joint Utilities file 3 separate ICA plans to CPUC July 2016 – Q2, 2017 – Monthly ICA WG meetings re/ICA implementation Q4, 2016 – Final Demo A report due Q4, 2016 – Long-term ICA refinement intermediate status report due Q2, 2017 – Utilities submit long-term ICA refinement final report due

5. 5 ICA WG Schedule - May 2 nd CPUC ruling Short Term: May 2 nd – end of Q4 2016 Update schedule for Demo A Results Recommend methods for evaluation of hosting capacity for 1) DER bundles or portfolios, responding to CAISO dispatch; and 2) Facilities using smart inverters Recommend format for ICA maps to be consistent and readable to all CA stakeholders Evaluate and recommend new methods that may improve computational efficiency of ICA tools and process Evaluate ORA’s recommendation to require establishment of reference circuits and reference use cases for comparative analyses of Demo Project A results Establish method for use of customer load data to develop more localized load shapes Establish definite timelines for future achievement of ICA milestones Long Term: May 2 nd -end of Q2 2017 Suggested topics include, but are not limited to: expansion to single phase feeders; data sharing; interactive ICA maps; market sensitive information; method for reflecting effect of load modifying resources; independent verification of ICA results; quality assurance and control measures Ongoing discussion in parallel with short term WG activities

6. 6 Element from Ruling time frame (short or long term) Date IOU completed or will complete Date(s) WG will discuss 3.1.a Update schedule for Demo A resultsshort termJuneJuly 3.1.b Recommend methods for evaluation of hosting capacity for the following resource types: i) DER bundles or portfolios, responding to CAISO dispatch; ii) facilities using smart invertersshort term June-September: Evaluation of Base Portfolio; September- December: Other Portfolios/techAugust 3.1.c Recommend a format for the ICA maps to be consistent and readable to all California stakeholders across the utilities' service territories with similar data and visual aspects (color coding, mapping tools, etc.)short termJuly-DecemberJuly 3.1.d Evaluate and recommend new methods that may improve the computational efficiency of the ICA tools and process in order to calculate and update ICA values across all circuits in each utility's service territory in updated ICAs more frequently and accuratelyshort termFebruary-DecemberAugust 3.1.e Evaluate ORA's recommendation to require establishment of reference circuits and reference use cases for comparative analyses of Demo Project A resultsshort termOctober-DecemberJuly 3.1.f Establish a method for use of Smart Meter and other customer load data to develop more localized load shapes to the extent that is not currently being doneshort termJanuary- June 2016August 3.1.g Establish definite timelines for future achievement of ICA milestones including frequency and process of ICA updatesshort termJune, DecemberDecember 3.2.a Methodology advancement and improvement: expansion of ICA to single phase feederslong term October, 2017 ongoing 3.2.b Methodology advancement and improvement: Ways to make ICA information more user friendly and easily accessible (data sharing)long term July, October, 2017 ongoing 3.2.c Methodology advancement and improvement: Interactive ICA mapslong termJuly-December July, 2017 ongoing 3.2.d Methodology advancement and improvement: Market sensitive information (type and timing of the thermal, reactance, or protection limits associated with the hosting capacity on each line)long term October, 2017 ongoing 3.2.e Methodology advancement and improvement: Method for reflecting the effect of potential load modifying resources on integration capacitylong term November, 2017 ongoing 3.2.f Methodology advancement and improvement: Development of ICA validation plans, describing how ICA results can be independently verifiedlong term November, 2017 ongoing 3.2.g Methodology advancement and improvement: Definition of quality assurance and quality control measures, including revision control for various software and databases, especially for customized or "in-house" softwarelong term November, 2017 ongoing Proposed Schedule for ICA WG topics

7. 7 Use Case Discussion Three ICA uses cases 1.Distribution planning 2.Interconnection process 3.Presentation of data

8. ICA Working Group Meeting July 25 th 8

9. ICA Use Case Overview Use CaseDescriptionApplication Interconnection Customers and third-parties can use ICA information to understand locations and amounts of DER capacity that can be interconnected without extensive upgrade costs or time. Near-term decision-making (1-3 years) due to ability forecast with needed certainty only in short-term. Planning Utilities to determine locations on distribution grid where future hosting capacity may be needed and when. ‒Incorporate DER Growth Scenarios as planning sensitivities. ‒Determine potential hosting capacity upgrades under different levels of growth ‒Results inform distribution planning Customers and third-parties can use ICA in combination with LNBA to assist in identifying optimal locations for DER development Guidance for procurement and solution development longer-term (3-10 years) recognizing values will change as forecast becomes more certain. 9

10. Interconnection/Rule 21 Coordination Utilize ICA to streamline Interconnection Study Process, improve level of certainty, and decrease interconnection costs Note: The following figures are illustrative of possible streamlining and may not reflect current process or discussions Coordination is necessary with Rule 21 Proceeding to properly incorporate/adopt ICA as part of the Rule 21 process 10

11. ICA Use Case: DER Planning (PG&E Perspectives only) Why do we need to plan for DER? DER penetration is becoming large enough to affect large-scale assets requiring long lead time projects or new complex DER solutions requiring testing and validation. This may cause interconnection delays. System conditions vary following the interconnection study. Regular planning studies need to ensure planned and existing DER do not impact the system under forecast scenarios Enables grid design for optimal resource placement and operation that is safe, reliable, and affordable under higher levels of DER penetration What questions need to be answered for this process? What actions are taken when DER growth is determined to exceed a location’s hosting capacity (i.e. proactive mitigation, encouraging complementary DER profiles, discouraging problematic DER)? How are hosting capacity upgrades determined given variety and complexity of solutions that can solve the issue? 11

12. Determine where and when future hosting capacity is needed ‒Incorporate DER growth scenarios as planning sensitivities ‒Perform ICA to determine when hosting capacity is projected to be reached under different growth scenarios What do we do with this information? ‒Inform distribution planning ‒Identify potential upgrades to accommodate different DER growth scenarios ‒Inform LNBA Load Load Capacity Distribution Need Hosting Need DER DER Capacity 20142015201620172018201920202021 20142015201620172018201920202021 12 ICA Use Case: DER Planning (PG&E Perspectives only)

13. 13 Discussion of Stakeholder Comments

14. 14 Stakeholder Comments DPA Site Selection: The location of Demo A projects should be discussed to ensure the ACR direction for “as broad a range as possible of electric characteristics” is met. PG&E provided a thorough discussion of its criteria and a presentation of how the two DPAs compared to the total territory for each criteria. The WG could ask for similar details from SDG&E and SCE before supporting their proposed locations. In addition, a cursory review of population data shows that over half of Californians live in dense metro centers near the coast (LA, San Francisco Bay/ San Jose, San Diego) which could have shorter circuits and less load variability than inland locations. Of the three utilities, only SCE includes a truly urban area near the coast (Johanna DPA). The WG should discuss potential shortcomings of running Demo A on circuits that could have low IC values relative to substation capacities based on the DPA selected. If addition, it is not clear what circuit/load conditions will trigger ICA protection and safety, and whether these conditions exist in the current DPA selections.

15. 15 Stakeholder Comments Modeling software: PG&E and SDG&E will use LoadSEER for load modeling and forecasting in the ICA. SCE states, "SCE has tested the LoadSEER software package from Integral Analytics and determined that the program’s current functionality does not adequately meet the forecasting needs of the SCE distribution planning process.” What are the unique needs of SCE’s distribution planning process that make LoadSEER inadequate?

16. 16 Stakeholder Comments Methodology: This was the first item in the ICA WG recommendations from June 1. ORA envisioned this would be the joint utility filing that compared the methodologies per ORA’s March 3, 2016 post-workshop comments (p. A-2.), but the Demo A plans do not provide a comparison across the IOUs. While more information has been added to the revised plans, key details are still missing: Spatial resolution of analysis vs. reporting, When and how is short-circuit analysis performed relative to power flow? Loads and analysis for 2, 576, or 8760 hours? How does the streamlined method for each IOU compare to the others and to the EPRI method? PG&E’s Figure 4 is nearly identical to SCE Figure 2, but the flow to/from the “ICA Calculations” is different, Per the May 2 ACR, description of ICA criteria and how they are applied will not be provided until the interim report due 3Q2016; Even if the benchmark/comparison assessment shows results to be comparable for a set of reference circuits, the details of each methodology should be transparent to help understand how they will be applied to the full set of circuits.

17. 17 Stakeholder Comments Methodology: As shown on the tables included in each of the utility’s plans regarding the “power system criteria to evaluate capacity limits”, there is some difference remaining between what criteria each utility intends to include in the Demonstration A analysis. In particular, under the category of Safety/Reliability, PG&E has indicated their intent to evaluate Islanding, Transmission Penetration, and Operational Flexibility (see PG&E at A-16). SCE and SDG&E, however, indicated that they do not intend to include Islanding, and SCE also is not planning to address Transmission Penetration at this time (see SCE at 10, SDG&E at 10). It would be helpful to understand the reasons for the differences in approach and the potential implications this will have on the Demonstration Projects, the comparability of the results, and their applicability to future efforts.

18. 18 Stakeholder Comments Methodology: Presenting/displaying ICA results for multiple scenarios of capacity (no reverse power flow to transmission system, maximum capacity regardless of reverse power) and growth (2-year growth, growth scenarios I and III). How do the IOUs intend to report/display these different combinations of results?

19. 19 Stakeholder Comments Methodology: Each of the IOU plans discussed some of the content to be included in the intermediate report to be released at the end of Q3 2016. The IOUs highlight that this report will include more details and discussion on the limitation criteria used. Encourage discussion of these criteria in the working group prior to this report being released. This process will be beneficial to ensure alignment between the IOUs and allow for transparency to the working group. As an example, the IOUs are not aligned on the safety limitation criteria to include in the ICA determination. Alignment of the limitation criteria may be desirable overall, but will be necessary for comparing methods.

20. 20 Stakeholder Comments Comparative assessment: There is a need for a plan to compare the streamlined and iterative results and computation times, both to each other and across IOUs. It will be important to discuss the collection of test feeders to use and the method for comparison. A rigorous comparison of results and computation time will help inform future decisions for evaluating ICA system wide.

21. 21 Stakeholder Comments Benchmarking and comparative assessment: This analysis was critical to WG support for the Demo A proposals, and is a key learning objective. However, the current plans do not provide enough detail to determine if the testing will yield meaningful results. For example, PG&E refers to an ERPI project with 16 feeders (p. A-33), SCE clearly states that six circuits will be used (p.22), and SDG&E did not state a number of circuits. This topic resulted in an animated discussion at the last meeting, particularly in terms of testing between methods vs. IOUs, and it remains an open issue.

22. 22 Stakeholder Comments Validation of results: The ruling stated that both Energy Division and ORA would be responsible for viewing and validating the inputs, models, limit criteria and results. Discuss the limitations (if any) on market participants’ ability to review this content and the conditions under which this will be possible. Working Group stakeholders interested in participating at this level of detail.

23. 23 Stakeholder Comments Reference circuits: PG&E says it is "willing to explore using the circuits in the demo and anonymizing them or EPRI California Solar Initiative circuits that were representative of the three IOUs” SCE says it will “work with other IOUs to apply both methods on six reference circuits (two circuits from each IOU’s demo A study with anonymization)” SDG&E says “SDG&E and the other IOUs will leverage the use of test circuits to perform the ICA and benchmark against each other.”

24. 24 Stakeholder Comments Use cases: Need for WG agreement on ICA use cases to help inform discussions about temporal and spatial granularity, result formats, and frequency of updates.

25. 25 Stakeholder Comments Other – learning objectives: Currently, each plan includes the same eight “learning objectives” (SCE adds two additional objectives) that are generally reiterations of the CPUC requirements. Requirements are not the same as learning objectives which are often in the form of questions to be answered through the proposed projects. For example, a key objective for all IOUs could be “Find the best ICA methodology and granularity of inputs, analysis, and results.” However, the learning objectives should be different for each IOU given that SCE and SDG&E are starting from scratch regarding the streamlined analysis, and PG&E has already applied this method across its entire service territory. Examples of utility specific objectives could be: SDG&E – Can SDG&E implement PG&E’s method, or improve on it, given SDG&E’s smaller service territory and computational needs? SCE –Will the iterative method work on SCE’s large territory? PG&E – What it required to extend the ICA beyond the substation bus and service transformer? Overall, learning objectives should provide concrete objectives that can be used on an ex poste basis to determine if the Demo projects have been successful.

26. 26 Stakeholder Comments Other – schedule: Schedules for Demo A should provide details and dependencies such that the WG can understand the scope and timing of individual tasks. This will help the WG prioritize topics for future meetings. The schedules should also provide time for methodological adjustments should the initial comparison/benchmark tests show accuracy limits for the streamlined method or computational limits for the iterative method. Also, milestones for related projects, e.g. EPIC 2.23, should be shown.

27. Power System Criteria Transmission Penetration (IREC): Increase levels of interconnected DER on the distribution circuits will have an effect on Transmission Systems Subsequent to Demo A work, intention is to continue the analysis on transmission ICA impacts IOUs recommends that transmission/subtransmission level of analysis be part of the longer-term work related to ongoing refinements to ICA under the ICA WG. 27

28. Power System Criteria Islanding (IREC): For UL certified inverters, SCE relies on the NRTL certification which incorporates an anti-islanding test procedure – UL Standard for Safety for Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources, UL 1741 section 46.3 For non-UL certified inverters, SCE and the customer install the sufficient protection equipment to meet the anti-islanding requirements – Refer to SCE’s Interconnection Handbook: https://www.sce.com/NR/rdonlyres/851128D1- 6820-43DD-BAD4-B30DE27B0F35/0/Interconnection_Handbook_090317.pdfhttps://www.sce.com/NR/rdonlyres/851128D1- 6820-43DD-BAD4-B30DE27B0F35/0/Interconnection_Handbook_090317.pdf SCE believes an anti-islanding limit is an overly-conservative approach to meeting the safety limitation, but is open to additional discussion 28

29. Power System Criteria Operational Flexibility (IREC): Consensus with IOUs was reached to apply a no-reverse power limit at the line section level – Likely the most limiting component for ICA values for areas with low loading levels – Expectation to explore other methods to ensure reliable system when switching – Limit would be removed to test the case of reverse power flow towards the transmission system to understand its impact on results 29

30. Power System Criteria Protection Criteria Streamlined Method: Utilize 10% reduction of reach per PG&E streamlined method – Maximum capacity allowed is based on 10% fault contribution at the point of interconnection. (aligns with Rule 21) Iterative Power Flow Method: Power flow tool to calculate the reduction of reach, taking into account existing distribution system protection systems and settings – Most impact to DER when: DER is connected to or near the end of long distribution lines DER is connected to areas of the distribution system that are electrically weak 30

31. Comparative Assessment Several alternatives for reference circuit selection (Vote Solar and ORA): – Utilize the a portion of the CSI circuits (two from each utility) Timing of Comparative Analysis: – Should allowed sufficient time to make corrections – Suggest August WG session should take place Mid-August to allow sufficient time for technical ICA evaluations and meet schedule 31

32. Learning Objectives Through the DRP Demonstration A Project, the IOUs hope to learn: – Capabilities, limitations, and applicability of two methods of analysis: Iterative power flow method Streamlined method – Overall capability of the distribution system to accept increasing levels of DER – Most common limiting factors, such as breaker limitations – Applicability of Smart Inverters – How high levels of DER on multiple feeders affect the distribution system – Capability of existing tool(s) to support large amounts of data for integration capacity analysis and publication 32

33. SCE SPECIFIC COMMENTS ICA Working Group Meeting July 25 th

34. Distribution Planning Area(DPA) Location Urban DPA Rural DPA CategoryUrban DPARural DPA RegionOrange CountyCentral Valley Service Area18 square miles120 square miles Number of Feeders3143 Number of Customers25,10049,700 Load Type Residential, Commercial, and light Industrial Residential, Commercial, and Agricultural 2016 Project Load217 MVA314 MVA SubstationsJohanna, Fairview, CamdenTulare, Hanford, Octol, Mascot, Goshen

35. Urban DPA Rural DPA Distribution Planning Area(DPA) Characteristics

36. Load Forecasting SCE is currently in the process of acquiring a set of Long-Term Planning Tools (LTPT) which includes Load and DER forecasting modules LTPT will be an integrated system with including planning tools, system analysis and project development. SCE expects that the load forecasting modules will provide the necessary forecasting capability required for the calculation of ICA and other functions Given SCE’s plan to initiate the RFP in the near term, SCE determine that it is not appropriate to use LoadSEER given the limitation to integrate LoadSEER with SCE’s existing systems – RFP will be open to industry as such LoadSEER may be evaluated as part of RFP if LaodSEER is able to fulfill the requirements of the RFP The load forecasting methodology utilized in Demo A is equivalent to LoadSEER

37. 37 Data and Maps ACR: 1.4.6a All information made available in this phase of ICA development shall be made available via the existing ICA maps in a downloadable format. The feeder map data shall also be available in a standard shapefile format, such as ESRI ArcMap Geographic Information System (GIS) data files. The maps and associated materials and download formats shall be consistent across all utilities and should be clearly explained through the inclusion of “keys” to the maps and associated materials. Explanations and the meanings of the information displayed shall be provided, including any relevant notes explaining limitations or caveats. Any new data types developed in the ICA working group shall be published in a form to be determined in the data access portion of the proceeding. 1.4.6b Existing RAM map information and ICA results shall be displayed on the same map. RAM information shall be the default information displayed on that map with ICA data available if the user specifies it

38. 38 Data and Maps Working Group activity relating to Demo Project A: 3.1.c. Recommend a format for the ICA maps to be consistent and readable to all California stakeholders across the utilities’ service territories with similar data and visual aspects (color coding, mapping tools etc). Establish a method for use of Smart Meter and other customer load data to develop more localized load shapes to the extent that is not currently being done. Working Group continued refinements to ICA methodology: 3.2.bWays to make ICA information more user-friendly and easily accessible (data sharing) 3.2.c Interactive ICA maps

39. Demo A ICA Map Use a separate layer to show the ICA results for Demo A DPAs Except key identification information (e.g., name, voltage class), the information currently available in other interconnection layers (ICA, RAM, etc.) will not be duplicated 24 sets of 24-hour load profiles (along with links for download) are added for DPA (system), Substation, and Circuit, in separate tabs Circuit-level customer type breakdown added to circuit level Line Section Level: Final ICA values (one for generation and one for load) will be presented in the main tab A breakdown of ICA values by limitation categories and by DER types will be shown in separate tabs Additional discussion on how hourly ICA profile will be presented is needed 39

40. Demo A ICA Map ICA values in different scenarios (Vote Solar) DER growth scenario Reverse/No reverse power flow scenario Alternatives: Toggle between different layers or different map symbology, with user guides provided Base layer is shown, additional scenarios are in downloadable format 40

41. Potential Demo A ICA Map Display DPA and Substation Line Section/Circuit 41

42. 42 Portfolio Analysis

43. DER Profile and Portfolio DER Profiles 1.Uniform Generation 2.Photovoltaic (PV) 3.PV with Tracker 4.PV with Storage 5.Uniform load 6.Electric Vehicle (EV)– Residential EV rate 7.EV – Workplace 8.EV – Residential TOU rate 9.Storage – Peak Shaving DER Portfolios 10.Solar 11.Solar and stationary storage 12.Solar, stationary storage, and load control 13.Solar, stationary storage, load control, and EV 43

44. 44 Summary & Next Steps

45. 45 www.drpwg.org