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A1507002 7-01-15 12:24 Pm FILED 7-01-15 12:24 PM A1507002 Appendix A: Acronyms AAEE Additional Achievable Energy Efficiency AB 327 California Assembly Bill 327 ANSI American National Standards Institute ARB California Air Resources Board AS Ancillary Services ATRA Annual Transmission Reliability Assessment CAISO California Independent System Operator Corporation CDA Customer Data Access CEC California Energy Commission CHP Combined Heat and Power CIP Critical Infrastructure Protection Commission, or CPUC California Public Utilities Commission CSI California Solar Initiative DER(s) Distributed Energy Resource (includes distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies) DERAC Distributed Energy Resource Avoided Cost DERiM Distributed Energy Resource Interconnection Maps DERMA Distributed Energy Resources Memorandum Account DG Distributed Generation DPP Distribution Planning Process DPRG Distribution Planning Review Group DR Demand Response DRP Distribution Resources Plan DRP Ruling Assigned Commissioner Ruling DRRP Data Request and Release Process DSP Distribution Substation Plan E3 Energy and Environmental Economics, Inc. EE Energy Efficiency 3 EIR Electrical Inspection Release EPIC Electric Program Investment Charge ES Energy Storage ESPI Energy Service Provider Interface EV Electric Vehicle FERC Federal Energy Regulatory Commission Final Guidance Guidance for Section 769 – Distribution Resource Planning, attached to the Assigned Commissioner’s Ruling on Guidance for Public Utilities Code Section 769 – Distribution Resource Planning, (February 6, 2015) (R.14-08-013) FLISR Fault Location Isolation and Service Restoration GHG Greenhouse Gas GIS Geographic Information System GRC General Rate Case GWh Gigawatt-hours ICA Integration Capacity Analysis IEC International Electrotechnical Commission IEEE Institute of Electrical and Electronics Engineers IERP Integrated Energy Policy Report IGP Integrated Grid Project IR Infrastructure Replacement IOU Investor-Owned Utility ITC Investment Tax Credit kW Kilowatt kWh Kilowatt-hours kV Kilovolts LCR RFO Local Capacity Requirements Requests for Offers LNBM Locational Net Benefits Methodology LTPP Long-Term Procurement Plan MAIFI Momentary Average Interruption Frequency Index 4 MPR Market Price Referent MW Megawatt MWh Megawatt-hour NEC National Electric Code NEM Net Energy Metering NERC North American Electric Reliability Corporation NPV Net Present Value O&M Operations and Maintenance OIR Order Instituting Rulemaking PEV Plug-in Electric Vehicle PUC California Public Utilities Code PRG Procurement Review Group PRP Preferred Resources Pilot PV Photovoltaic RA Resource Adequacy RECC Real Economic Carrying Charge RFO Request for Offer RPS Renewables Portfolio Standard Rule 21 Rule 21 Electric Tariffs SAIDI System Average Interruption Duration Index SAIFI System Average Interruption Frequency Index SCADA Supervisory Control and Data Acquisition SCE Southern California Edison Company SGIP Self-Generation Incentive Program SONGS San Onofre Nuclear Generating Station TOU Time-of-Use TPP Transmission Planning Process TSP Transmission Substation Plan 5 T&D Transmission and Distribution UL Underwriters Laboratories V1G Managed charging (unidirectional) V2G Bi-directional power flow VGI Vehicle-Grid Integration VAR Volt-Ampere Reactive WDAT Wholesale Distribution Access Tariff 6 Appendix B: Final Guidance and AB 327 Compliance 7 Final Guidance Requirement Location in SCE's DRP 1. Integration Capacity and Locational Value Analysis: This section directs the Utilities to develop three analytical frameworks related to the grid integration capacity of DER, the quantification of DER locational value, and the future growth of DERs. The intent being to create a set of mutually supportive tools that at once detail how much DER can be deployed under a business as usual grid investment trajectory, while building the capabilities to compare portfolios of DERs as alternatives to traditional grid infrastructure. In recognition of the fact that the Utilities have started elements of this work already, they are directed to take into account work they have previously conducted, or are currently working on, through their Smart Grid Deployment Plans and their EPIC Investment Plans. a) Integration Capacity Analysis (ICA): This analysis will specify how much DER hosting Chapter 2, Section B capacity may be available on the distribution network. Worksheets should be provided Appendix I: Integration by the Utilities that show evaluation of available capacity down to the line section or Capacity Analysis node level. One of the goals of this analysis is to improve the efficiency of the grid Worksheets interconnection process through coordination between this work product and each Utility’s Rule 21 interconnection, Rule 15 main extensions and Rule 16 service connection study processes. To implement this analysis, the Utilities shall do the following in their DRP filings: i) Perform a distribution system Integration Capacity Analysis down to the line Chapter 2, Section B, section or node level, utilizing a common methodology across all Utilities. This Subsections 3 and 7 analysis quantifies the capability of the system to integrate DER within thermal ratings, protection system limits and power quality and safety standards of existing equipment. Results of the analysis are to be published via online maps maintained by each Utility and available to the public. ii) Perform an analysis that assesses current system capability together with Chapter 2, Section B, any planned investments within a 2 year period. Clearly articulate the assumptions Subsection 6 and methodology used for load and DER forecasts over the 2 year period. iii) Perform an analysis using dynamic modeling methods, which are uniform Chapter 2, Section B, across all Utilities, and circuit performance data. The analysis shall avoid the use of Subsections 3 heuristic approaches where possible. iv) Assess the state of DER deployment and DER deployment projections. For Chapter 2, Section B, each of the identified DERs, the Utilities should provide current levels of deployment Subsection 2 territory wide, plus an assessment of geographic dispersion with circuits that exhibit high levels of penetration identified. v) If a Utility is unable to conduct dynamic analyses for all feeders down to the Chapter 2, Section B, line section or node, as an initial phase the Utility shall conduct an integration Subsections 4 capacity analysis on a select set of representative circuits, including all related line sections. Utilities shall agree, as necessary, on the methodology used to select the representative circuits. The Utilities must include their methodology for selecting representative circuits as part of this analysis. vi) Specify a process for regularly updating the Integration Capacity Analysis to Chapter 2, Section B, reflect current conditions. The process in place for updating the Renewable Auction Subsection 8 Mechanism monthly is a good starting point. Where current Utility capabilities are inadequate to conduct a dynamic, line section -level integration capacity analysis, specify a plan for developing these capabilities, including a schedule. vii) Specify recommendations for utilizing the Integration Capacity Analysis to Chapter 2, Section B, support planning and streamlining of Rule 21 for distributed generation and Rule 15 Subsection 9 and Rule 16 assessments of EV load grid impacts, with a particular focus on developing new or improved ‘Fast Track’ standards. 8 b) Optimal Location Benefit Analysis: This analysis will specify the net benefit that Chapter 2, Section C DERs can provide in a given location. To implement this analysis, the Utilities shall develop the following and file as part of their DRPs: i) A unified locational net benefits methodology consistent across all three Chapter 2, Section C, Utilities that is based on the Commission approved E3 Cost-Effectiveness Calculator, Subsection 2 but enhanced to explicitly include location-specific values, and at minimum include the following value components: 1. Avoided Sub-transmission, Substation and Feeder Capital and Chapter 2, Section C, Operating Expenditures Subsection 3e 2. Avoided Distribution Voltage and Power Quality Capital and Operating Chapter 2, Section C, Subsection 3f 3. Expenditures Distribution Reliability and Resiliency Capital and Chapter 2, Section C, Operating Expenditures Subsection 3g 4. Avoided Transmission Capital and Operating Expenditures: Chapter 2, Section C, Subsection 3e 5. Avoided RA purchases -- to include system, local and flexible RA (where Chapter 2, Section C, applicable) Subsection 3c 6. Avoided Renewables Integration Costs Chapter 2, Section C, Subsection 3j 7. Avoided societal costs clearly linked to DER deployment Chapter 2, Section C, Subsection 3k 8. Avoided public safety costs clearly linked to DER deployment Chapter 2, Section C, Subsection 3l 9. Definition for each of the value components included in the locational Chapter 2, Section C, benefits analysis Subsection 3 10. Definition of methodology used to assess benefits and costs of each Chapter 2, Section C, value component explicitly outlined above, Subsection 3 11. Description of how a locational benefits methodology can be Chapter 2, Section C, integrated into long-term planning initiatives like the TPP, LTPP, and the IEPR Subsection 6 ii) Maintenance and Updates to Locations Analysis: A process for maintaining Chapter 2, Section B, on-going updates to
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