Details for: PGE AL 5300-E-A v2.pdf

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Erik Jacobson
Regulatory Relations

Pacific Gas and Electric Company
77 Beale St., Mail Code B13U
P.O. Box 770000
San Francisco, CA 94177
Fax: 415-973-3582

December 3, 2018
Advice 5300-E-A
(Pacific Gas and Electric Company ID U 39 E)

Public Utilities Commission of the State of California

Supplemental: Updated Grid Modernization Classification Tables in
Response to the Decision on Track 3 Policy Issues, Subtrack 2 (D. 1803-023)

The purpose of this Supplemental Advice Letter (AL) is to further update Pacific Gas and
Electric Company’s (PG&E’s) Grid Modernization Classification Tables (Appendices B
and C) (together, the “Grid Mod Tables”, in accordance with Ordering Paragraph (OP) 3
of Decision (D.) 18-03-023.
The proposed updates are being submitted as a result of discussions between the
California Public Utilities Commission’s (CPUC’s) Energy Division staff, the CPUC’s
Public Advocates Office, and the large investor-owned utilities (PG&E, Southern
California Edison Company and San Diego Gas & Electric Company) (collectively, the
“IOUs”) to better align the Grid Mod Tables across the IOUs.
On March 22, 2018, the Commission issued D. 18-03-023, Decision on Track 3 Policy
Issues, Sub-track 2 (Grid Modernization), requiring the IOUs to submit updates to the
Grid Mod Tables.
In compliance with Ordering Paragraph 3 of Decision (D.) 18-03-023, PG&E submitted
AL 5300-E on May 21, 2018, for approval of its updates to the Grid Mod Tables in
compliance with OP 3 of D.18-03-023.
On June 12, 2018, the Public Advocates Office (formerly Office of Ratepayer Advocates)
submitted its protest to PG&E Advice 5300-E (ORA Protest).1

Protest of the Office of Ratepayer Advocates to Pacific Gas and Electric Company’s Advice
Letter 5300-E, Southern California Edison Company’s Advice Letter 3807-E, and San Diego
Gas & Electric Company’s Advice Letter 3229-E Regarding the Updated Grid Modernization
Classification Tables Pursuant to Decision 18-03-023 (“ORA Protest”).


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Advice 5300-E-A -2- December 3, 2018 In response to Energy Division’s request, the IOUs met on several occasions to try and better align the Grid Mod Tables across our respective companies. This supplemental advice letter supplements PG&E AL 5300-E in part and replaces Appendices B and C of PG&E AL 5300-E. Updates to the Classification of Grid Modernization Investments Table and Classifications Definitions In addition to the edits PG&E provided to Appendix B of the Decision (Classification of Grid Modernization Investments) in its previous Advice 5300-E, PG&E has made additional updates to better align across the IOUs. Furthermore, the singular PG&E’s Technology Category, Grid Management System (GMS) was updated to plural, Grid Management Systems. This more accurately reflects that the GMS is comprised of a collection of multiple software systems. The specific software technology categories were moved to the example columns under GMS to better align with the other IOUs’ format. Finally, PG&E’s System Modeling Toolset and LongTerm Planning Tools were combined into a single Technology Category labeled as Short and Long-Term Planning Tools. Updates to the Classification Definitions were made in conjunction with these Technology Category changes. Attachments Attachment A: Updates to Appendix B of D.18-03-023, Classification of Grid Modernization Investments Attachment B: Updates to Appendix C of D.18-03-023, Classification Definitions Protests Pursuant to CPUC General Order 96-B, Section 7.5.1, PG&E hereby requests the protest period be waived. Effective Date PG&E requests that this supplemental Tier 2 advice have the same effective date as PG&E advice letter 5300-E. Notice In accordance with General Order 96-B, Section IV, a copy of this advice letter is being sent electronically and via U.S. mail to parties shown on the attached list and the parties on the service list for R.14-08-013 and A.15-07-006. Address changes to the General Order 96-B service list should be directed to PG&E at email address For changes to any other service list, please contact the
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Advice 5300-E-A -3- December 3, 2018 Commission’s Process Office at (415) 703-2021 or at Send all electronic approvals to Advice letter submittals can also be accessed electronically at: /S/ Erik Jacobson Director, Regulatory Relations Attachments cc: Gabe Petlin – Energy Division Dina Mackin – Energy Division Thomas Roberts – Public Advocates Office Tim Drew – Public Advocates Office Chloe Lukins, Public Advocates Office Nelly Sarmiento, Public Advocates Office Service Lists for R.14-08-013 and A.15-07-006
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ADVICE LETTER SUMMARY ENERGY UTILITY MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Company name/CPUC Utility No.: Pacific Gas and Electric Company (ID U39E) Utility type: ELC GAS PLC ✔ HEAT ELC = Electric PLC = Pipeline WATER Contact Person: Yvonne Yang Phone #: (415)973-2094 E-mail: E-mail Disposition Notice to: EXPLANATION OF UTILITY TYPE GAS = Gas WATER = Water HEAT = Heat (Date Submitted / Received Stamp by CPUC) Tier Designation: 2 Advice Letter (AL) #: 5300-E-A Subject of AL: Supplemental: Updated Grid Modernization Classification Tables in Response to the Decision on Track 3 Policy Issues, Subtrack 2 (D. 18-03-023) Keywords (choose from CPUC listing): Compliance AL Type: Monthly Quarterly Annual ✔ One-Time Other: If AL submitted in compliance with a Commission order, indicate relevant Decision/Resolution #: D.18-03-023 Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: No Summarize differences between the AL and the prior withdrawn or rejected AL: Yes Yes ✔ No ✔ No 6/20/18 No. of tariff sheets: N/A Estimated system annual revenue effect (%): N/A Estimated system average rate effect (%): N/A When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting). Tariff schedules affected: N/A Service affected and changes proposed1: N/A Pending advice letters that revise the same tariff sheets: N/A 1 Discuss in AL if more space is needed. Clear Form
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Protests and all other correspondence regarding this AL are due no later than 20 days after the date of this submittal, unless otherwise authorized by the Commission, and shall be sent to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Avenue San Francisco, CA 94102 Email: Name: Erik Jacobson, c/o Megan Lawson Title: Director, Regulatory Relations Utility Name: Pacific Gas and Electric Company Address: 77 Beale Street, Mail Code B13U City: San Francisco, CA 94177 Zip: 94177 State: California Telephone (xxx) xxx-xxxx: (415)973-2093 Facsimile (xxx) xxx-xxxx: (415)973-3582 Email: Name: Title: Utility Name: Address: City: State: District of Columbia Telephone (xxx) xxx-xxxx: Facsimile (xxx) xxx-xxxx: Email: Zip: Clear Form
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Advice 5300-E-A December 3, 2018 Attachment A (PG&E Updates to Appendix B of D.18-03-023)
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HDA, S&R, GDS Grid Analytics Application Interconnection Processing HDA, S&R, GDS Tool HDA, S&R, GDS Data Sharing Portals Application Assessment and Processing Circuit/System Modeling DER Valuation, Solution Analysis, Circuit Modeling DER Forecasting, DER Valuation Solution Analysis, Circuit Modeling HDA, S&R, GDS Long and short term Planning Tools Circuit modeling, Data Used for Forecasting and DER Value and Solution Analysis C. Function (numbers refer to Appendix C, Part C of the Classification Definitions) All except #2 HDA, S&R, GDS GDS= Grid and DER Services HDA= High DER Adoption S&R= Safety and Reliability B. Use Cases specific to current CA IOU's Intent: Grid Management Systems HDA, GDS, S&R (GMS) Grid Connectivity Model A. Technology Category System wide System wide System wide System wide System wide System wide Service Planning and Customer Engagement Distribution Planning Grid Operations Distribution Planning Distribution Planning Distribution Grid Operations Distribution Planning, Grid Operations, Market Operations D. System wide Distribution System Management or Local Activities and Responsibilities Deployment of Technology EV, DG, ES EV, DG, ES EE, DR, EV, DG, ES EE, DR, EV, DG, ES PEV, DG, ES, DR EV, DG, ES E. DERs that apply toward IOU's Technology Deployment Plan Indirect impact on sustain voltage violations, thermal, protection interconnection process) Sustained voltage violations, thermal, protection, asset management Sustained voltage violations, thermal, protection Thermal, Operational Limitations All items Items 1 8 of list of challenges TBD TBD TBD Customer facing TBD application to support streamlining the interconnection process, improve distribution planning, Integration Capacity Analysis (ICA) Asset management, sensing and measurement (data), improves quality of asset data to improve distribution planning inputs and operational decisions Data Sharing Portal (web interface) Integration Capacity Analysis (ICA), Locational Net Benefit Analysis Tool (LNBA) Autonomous and /or Targeted Autonomous and /or Targeted Autonomous and /or Targeted Autonomous and /or Targeted Autonomous and /or Targeted Autonomous and /or Targeted Utility GRC Application Autonomous DER Growth Volume and Category and/or Targeted DER specific to Grid Mod Deployment Technology Deployment for DER Integration* Distributed Energy Resource TBD Management System (DERMS), Advanced Distribution Management System (ADMS), Demand Response Management System (DRMS), DER Head End, and VVO. Integrated Load TBD and DER forecasting, solution analysis for capacity/reliability, LoadSEER, Power flow modeling and analysis of distribution feeders (CYME) Base data layer for ICA, Load and DER forecasting, state estimation, ArcGIS, EDGIS F. System/ Integration CA IOU Examples of Grid Mod Challenges Addressed Technology Deployment Related (numbers refer to to DER Integration Appendix C, Part F of the Classification Definitions)
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Sensing & Measurement, Data & Device Communications, Control & Feedback Systems, Reliability Management Sensing & Measurement, Data & Device Comms. Sensing and Measurement, Data & Device Communications, Cybersecurity Sensing and Measurement, Data & Device Communications, Cybersecurity Fault Location Isolation HDA, S&R System Restoration (e.g. Intelligent Automated Switches) S&R S&R, GDS S&R, GDS Remote Fault Indicators Field Area Network Wide Area Network Distribution Planning, Grid Operations, Market Operations Distribution Planning, Grid Operations, Market Operations Distribution Planning, Grid Operations, Market Operations Distribution Planning, Grid Operations, Market Operations Large Local Distribution Planning, Grid Areas, eventually Operations, Market system Operations wide Large Local Distribution Planning, Grid Areas, eventually Operations, Market system Operations wide Local Local Local Sensing & Measurement, Data & Device, Communications Control & Feedback Systems Volt/Var Optimization HDA, S&R, GDS Local & System Wide Sensing & Measurement, Data & Device Communications, Control & Feedback Systems, Reliability Management, Cybersecurity Grid Operations D. System wide Distribution System Management or Local Activities and Responsibilities Deployment of Technology Substation Automation and HDA, S&R, GDS Common Substation Platform (CSP) C. Function (numbers refer to Appendix C, Part C of the Classification Definitions) Local & System wide GDS= Grid and DER Services HDA= High DER Adoption S&R= Safety and Reliability B. Use Cases specific to current CA IOU's Intent: Adaptive Protection System S&R A. Technology Category EV, DG, ES EV, DG, ES EV, DG, ES EV, DG, ES EV, DG, ES EV, DG, ES EE, DR, EV, DG, ES E. DERs that apply toward IOU's Technology Deployment Plan Items 1 10 of list of challenges Thermal, Operational Limitations, Cybersecurity Items 1 10 of list of challenges Thermal, Operational Limitations, Fault Location & Service Restoration, Cybersecurity Voltage fluctuation, sustained voltage violations, Low (Secondary) Voltage Controllers, Conservation Voltage Reduction Items 1 10 of list of challenges Protection Fiber optic and IP connectivity Wireless radios, Routers Wireless bidirectional fault indicators Remote Intelligent Switches, Augmented Remote Control Switches, Automatic Reclosers Substation Load Tap Changers, Voltage Regulators, Automated programmable capacitor controls, integration with DMS and EMS, future integration with smart inverters SCADA, coordinated distribution device control with DERs, protection, cybersecurity TBD TBD TBD TBD TBD TBD Autonomous and /or Targeted Autonomous and /or Targeted Autonomous and /or Targeted Not Applicable Autonomous and /or Targeted Autonomous and /or Targeted Utility GRC Application Autonomous DER Growth Volume and Category and/or Targeted DER specific to Grid Mod Deployment Technology Deployment for DER Integration* This is typically incorporated as part TBD of the Common Substation Platform (CSP) at the substation level. In the future, it may be incorporated into ADMS. F. System/ Integration CA IOU Examples of Grid Mod Challenges Addressed Technology Deployment Related (numbers refer to to DER Integration Appendix C, Part F of the Classification Definitions)
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S&R HDA, GDS, S&R HDA, S&R Remote Controlled Switches DER Hosting Capacity Reinforcement Relay Replacement Local Control & Feedback Systems Local System Planning, Grid Operations Grid Operations Distribution Planning, Grid Operations, Distribution Planning, Grid Operations, Market Operations D. System wide Distribution System Management or Local Activities and Responsibilities Deployment of Technology Capacity (Missing Local from Appendix C, Part C) Control & Feedback Systems Sensing & Measurement, Data & Device Comms. C. Function (numbers refer to Appendix C, Part C of the Classification Definitions) * GRC categories to be determined upon preparing and filing of the GRC. HDA, S&R, GDS GDS= Grid and DER Services HDA= High DER Adoption S&R= Safety and Reliability B. Use Cases specific to current CA IOU's Intent: Grid Sensors A. Technology Category EE, DR, EV, DG, ES EE, DR, EV, DG, ES EE, DR, EV, DG, ES EV, DG, ES E. DERs that apply toward IOU's Technology Deployment Plan Protection Thermal Operational Limitations Thermal, Operational Limitations, Fault Location & Service Restoration, Cybersecurity TBD TBD TBD Autonomous DER Growth and Targeted DER Deployment Autonomous DER Growth and Targeted DER Deployment Autonomous and /or Targeted Utility GRC Application Autonomous DER Growth Volume and Category and/or Targeted DER specific to Grid Mod Deployment Technology Deployment for DER Integration* Upgrading legacy protection relays TBD on as needed basis Installing new manual switches, upgrading sections of cable/ conductor, extending feeder lines to create new ties Typically, incorporated with other devices/systems such as SCADA reclosers, and FLISR schemes. Typically, incorporated with other devices/systems such as SCADA reclosers, and FLISR schemes. F. System/ Integration CA IOU Examples of Grid Mod Challenges Addressed Technology Deployment Related (numbers refer to to DER Integration Appendix C, Part F of the Classification Definitions)
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PGE AL 5300-E-A December 3, 2018 Attachment B (PG&E Updates to Appendix C of D.18-03-023)
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APPENDIX C Classification Definitions A. Technology Types Included in Grid Modernization This list summarizes the technologies included in the classification of Grid Modernization investments. Items marked with a “*” indicate tools and technologies that are implemented on a system wide basis. All other tools and technologies are implemented at a local grid level. 1. Grid Connectivity Model *: The Grid Connectivity Model (EDGIS for PG&E) represents the software database and model of the complete electrical grid containing all electrical and geo-spatial attributes. The Grid Connectivity Model, including the as-built GIS models and as-operated operating models, feeds into all other Grid Modernization software tools that utilize grid data to perform planning and real-time operations analysis. 2. Interconnection Processing Tool*: Single web-based user interface that provides a common platform for all stakeholders (both internal and external) to interact throughout the interconnection process. More specifically, it allows customers to submit interconnection requests for generation, load, and combinations thereof connecting under any interconnection tariff or connecting as load. 3. Short & Long-Term Planning Tools*: Software tools required for integrated grid planning and time-series forecasting up to a ten-year horizon to identify optimal solutions to system planning challenges. The Planning Tools are capable of importing information from other Grid Modernization software tools that assist with planning activities, thereby producing a single interface for electric system planners. 4. System Modeling Toolset (CYME for PG&E)*: Models multiple levels of the electric system and acts as an interface between transmission and distribution to support analyses including Integration Capacity Analysis (ICA) and interconnection studies. Performs accurate analysis of electric system power flows to assist with both planning and operations, providing more detailed information to ensure voltage limits, thermal limits, and protection settings continue to be met as DER penetration increases. 5. Data Sharing Portal*: User-friendly, web-based interface(s) that provides customers with immediate access to available information regarding forecasted planning needs, future projects, and circuit interconnection capacities, such as the information included in the Integration Capacity Analysis (ICA), Locational Net Benefits Analysis (LNBA), Grid Needs Assessment (GNA), and Distributed Deferral Opportunity Report (DDOR) required by the Commission in the Distribution Resources Plan (DRP). The Data Sharing Portal will provide
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transparent planning information to promote customer choice and enable opportunities for DERs as well as streamline the interconnection process. 6. Grid Analytics Applications*: Software tools that 1) provides a user interface between engineers, operators, and distribution grid planners in using integrated data across multiple software platforms, including smart meter data, weather data, outage data and SCADA data, 1 and 2) enables system planners to utilize preprocessed, statistically analyzed data on historical field measurement trends, circuit voltage drop, line transformer utilization, phase identification, operating circuit violations, and accuracy of transformer to meter relationships. This data improves the accuracy of System Planners’ long-term electric system planning analyses and modeling, which the planners perform using other Grid Modernization software. 7. Grid Management Systems (GMS)*: To support and provide essential functions for grid operators, GMS is envisioned to be a collection of software systems that receives near real-time telemetry from grid devices (including DERs), analyzes the data, and controls the grid devices in order to optimize power flows, respond to fault conditions, or manage microgrids--among many other functionalities. GMS may consist of multiple related software systems, or a single software package that includes all functions, including the Advanced Distribution Management System (ADMS), Distributed Energy Resource Management System (DERMS), Demand Response Management Systems (DRMS), Device Management System, Adaptive Protection System (APS), Volt/VAR Optimization, and Integration Bus Technology (PG&E). The ADMS and DERMS are deeply integrated and comprise the largest components of the GMS. When implemented, the ADMS and DERMS serve as the interface between operators in the control centers and the grid devices, help to manage DERs, control grid assets, and facilitate operations in response to or to prepare for grid events (e.g. planned and unplanned outages and load/generation transfers). From a functional capability perspective, ADMS, and the associated communication and control upgrades, provides real-time situational awareness and analysis, power flow optimization, operational planning, and reconfigurable protection. DERMs will enable real-time control and monitoring of DER smart inverters, enabling DERs to minimize grid impacts as well as providing grid services under the right conditions. DRMS includes many modules that included functions needed to manage DR resources. 2 DRMS is considered a mature technology. 8. FLISR: Fault Location, Isolation, and Service Restoration (FLISR) technologies and systems involve field hardware, communications systems, and software to automate power restoration and reduce the area and length of power outages. Automatically isolating the faulted areas re-energizes non-affected 1 Supervisory control and data analysis. U.S. Department of Energy “Modern Distribution Grid Volume II: Advanced Technology Assessment,” Version 1.1, March 27, 2017, pp. 33-34 2
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customers more quickly and locates trouble areas for field crews to speed restoration. 9. ADMS: An Advanced Distribution Management System (ADMS) is a software platform that aids Distribution Operators, Engineers, and other personnel in monitoring, controlling, and optimizing the distribution grid to provide safe, reliable, and affordable energy for customers. A DMS is often called “Advanced” if it includes automated applications that leverage the core mapping and DSCADA functionality such as on-line power flow, FLISR, Switch Order Management, VVO, etc. 10. DERMS: As an emerging technology, the definition of Distributed Energy Resource Management System (DERMS) technology is still evolving. In general, it can be classified as a software platform that can manage a variety of both aggregated and individual DERs to support various objective functions related to grid support, customer value, or market participation. 11. DRMS: The IT system that processes enrollments, registration to the CAISO, management of aggregated resources, dispatch events of PG&E’s DR events and retail settlements. 12. DER Head-End: The DER Head-End is a software system that enables utilities to interact with DERs and aggregations of DERs across programs, resource types and protocols. The primary functions of the utility DER Head-End are to consolidate data to/from diverse DER types (e.g. solar, storage, electric vehicles, load control, DR platforms) and/or aggregations of DERs and pass coherent data to/from utility systems and applications (e.g. ADMS, DERMS optimization engines, forecasting). The DER Head-End is a communication and data layer that provides streamlined integration, interoperability and scalability across DERs types and utility applications. 13. Adaptive Protection System (APS)*: The Adaptive Protection System, an integrated software system, will evaluate protection settings and schemes on current protection devices based upon real-time system topology and conditions and provide updated relay settings to these devices. This will ensure the devices operate as intended based on current grid topology and operating conditions, supporting adequate and coordinated system protection. 14. Volt/Var Optimization: The objective of a Volt VAR Control /Optimization (VVO) systems is to manage voltage and VARs on the system to achieve specific goals, most often voltage /VAR compliance and Conservation Voltage Reduction (CVR). CVR reduces energy usage by lowering service voltages on specific areas of the system with load types that are responsive to CVR, while maintaining overall customer service voltage requirements (per CPUC Rule 2 criteria for customer allowable voltage limits and ANSI C84.1). VVO allows for greater circuit voltage control as DER behavior changes throughout the day affecting a circuit’s voltage profile. VVO is often a centralized automated control system that coordinates
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substation and field SCADA assets including substation LTCs, voltage regulators, and capacitor banks to optimize voltage and VARs in the system. There is also the potential to incorporate low voltage devices with more localized impacts. 15. Wide Area Network*: Wide Area Network (WAN) program includes: (1) historical program of installing fiber optic cable interconnecting substations and control centers to enable real-time data transmission and control functions; and (2) installation of hardware and software to convert the data protocol to an internetbased protocol (IP) in order to transmit data through the FAN and to take advantage of the faster speed of the fiber optic cable. The WAN relies on an internet-based protocol to match the communication protocol of the FAN and enhance cybersecurity via a more robust and secure network. FAN data is backhauled through the WAN with the Common Substation Platform (CSP) providing security services between FAN and WAN. 16. Field Area Network*: The Field Area Network (FAN) is a wireless communication system that provides connectivity of data and control functions to Distribution Automation (DA) devices, Distributed Energy Resources (DERs), and Commercial and Industrial meters. Components of the FAN include a set of wireless radios and routers that support all the cybersecurity, performance, and operational requirements needed to support current distribution automation assets, as well as advanced Grid Modernization capabilities. These advanced capabilities may include automated switching, fault interruption, real-time situational awareness, and reliable integration of non-wires solutions. FAN, along with cybersecurity upgrades, will also provide secure communications between back office control systems and field devices. 17. Substation Automation and Common Substation Platform (CSP): The CSP is a computing platform located in the substation that acts as a control hub, connecting devices in the field to back office systems. The CSP communicates via a suite of technologies such as distribution automation equipment through the Field Area Network (FAN) wireless communication network, and it communicates from the substation to the ADMS and DERMS back office systems through the WAN high speed network. This suite of technologies provides the high-speed connectivity needed to give system operators the near real-time understanding of the state of the grid. The CSP computing platform (hardware and software) is designed for twoway communication: to enable secure remote data acquisition from circuit devices (i.e. consumer of data) and provide remote and automatic control over circuit devices (i.e. sender of data). It employs common cybersecurity tools to monitor traffic from FAN and WAN into the substation. 18. Relay Replacement: Certain protection relay devices could be unreliable under the condition of load encroachment caused by additional DER generation. This is due to the fact that most legacy distribution relaying devices are not equipped to support two-way power flows. Such protective relays could operate incorrectly when experiencing reverse power flow, which would increase equipment outages and increase customer service interruptions. To provide safe and reliable integration of
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DERs on the system, the protective relaying scheme and related infrastructure will need to be improved. One option is to upgrade legacy protection relays with new ones when reverse flow may exist. The new microprocessor protection relays are equipped with the capability to provide load encroachment, voltage polarized directional sensing, and ground overcurrent protection. These capabilities can accommodate reverse power flow created by DERs and protect the downstream/upstream circuits. 19. Intelligent Automated Switches: Remote-controlled switches with advanced telemetry that provides grid operators with real-time visibility of electric system characteristics such as voltage, current, power flow direction, and fault location information. Installation of remote-controlled switches with advanced telemetry capabilities replaces the ongoing deployment of similar devices that lack these capabilities. These devices are necessary to facilitate outage restoration and enable self-healing circuit capabilities, sometimes referred to as fault location, isolation, and service restoration (FLISR) technology. In addition to providing increased visibility to the grid, these switches and associated automated schemes allow for quick and remote reconfiguration of the distribution system in response to abnormal or emergency situations by having the ability to coordinate with operational systems and/or neighboring devices. 20. Remote Controlled Voltage Devices: Devices in the substation and on distribution circuits that impact voltage include load tap changers, voltage regulators, and capacitor banks. Each of these devices can be purchased, and in some cases retrofitted, to allow remote operation by grid operators or automatically by VVO software. VVO systems rely on remote or manually controlled voltage devices. 21. Remote Fault Indicators: Remote fault indicators (RFIs) are stand-alone grid sensors that provide grid operators with real-time visibility of electric system characteristics such as current, power flow direction, and fault location information. This decreases the time to respond to abnormal conditions, potentially avoiding overload conditions, and reduces customer outage time since field workers can be directed to the faulted line section, reducing their travel and troubleshooting times. 22. Grid Sensors: Equipment capable of providing gathering data such as directional current flow, fault location identification, and voltage at various locations along distribution lines and transmit that data to the distribution control center and grid management systems for near-real time viewing by grid operators and electric system planners. Sensing of voltage and current require instrumentation transformers, local measurement devices, and a communication interface. Grid sensors can eventually be incorporated into all new devices installed on distribution lines including but not limited to Intelligent Automated Switches and Remote Fault Indicators. 23. Primary Circuit Reinforcement: Grid reinforcement consists of the local upgrades needed to solve distribution needs that arise due to increased DER (e.g., mitigation of overloads, facilitate load balancing, or due to increased DER-hosting
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capacity needs). The upgrades include installing new switches (manual, remote controlled, and intelligent), upgrading sections of cable, or installing conductor to create circuit ties, and extending lines (poles, conductor, insulators, etc. for overhead lines and trenching, cable, and conduits for underground extensions) to create ties between circuits. This could also include upgrades to 4kV substations, including cutovers and eliminations. B. Grid Modernization Use Cases Grid investments may serve multiple use cases or objectives. These use cases are necessary to distinguish in order to identify the drivers of costs and benefits to customers. These use cases are: 1. High DER Adoption: PG&E plans to forecast autonomous growth of DERs that result from existing policies, such as NEM 3 and SGIP. 4 This use case refers to functions and capabilities necessary to safely and reliably plan and operate the distribution system while accommodating the levels of DER adoption anticipated by California's current policies. This use case also refers to enhanced utility tools and processes that streamline and expedite the customer interconnection process. This DER growth consists of customer adoption driven by existing tariffs and programs. 2. Grid and DER Services: DERs targeted for specific locations, such as those being piloted in the Integrated Distributed Energy Resources (IDER) Incentives pilot 5 and considered in the DRP Distribution Investment Deferral Framework (Track 3 Sub-track 3), may provide an alternative to traditional wires solutions by providing capacity, voltage support, and/or enhanced reliability on a circuit. To enable DERs to provide grid services, where cost effective, the distribution planning process should identify opportunities for DERs to defer or avoid traditional capital investments. This use case refers to functions and capabilities needed to enable DERs to provide grid services whereby the DERs provide a specific service to maintain the safety and reliability of the distribution grid. It also refers to functions and capabilities needed to enable DERs to participate in wholesale markets. 3. Safety and Reliability: This use case refers to functions and capabilities that are needed to maintain or improve safety and reliability throughout the electric system, independent of DER growth. These investments are required to maintain the safety of the public and field personnel working on the electric system while providing customers with reliable electric service. Although these investments are needed for safety and reliability purposes, irrespective of the levels of DER growth, these investments may provide additional benefits and enable higher DER adoption. 3 Net Energy Metering Self-Generation Incentive Program 5 Adopted by D.16-12-036. 4
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C. Functions of Grid Modernization The section categorizes grid modernization technologies based on their function in distribution system management. These categorizations are defined by the IOUs and informed by the U.S. Department of Energy’s DSPx project. 6 1. DER Forecasting: DER forecasting refers to estimating future changes in net electrical power flows resulting from increased DER adoption. These forecasts should reflect power flow changes with sufficient temporal and spatial resolutions to support both shortterm and long-term planning efforts. As described in DSPx, the operational forecasting software tools assess how the “hidden load” challenge, which is the complication of distinguishing between supply resources (distributed generation and storage) and gross demand, impacts the ability to accurately forecast under various operation conditions. There are various methods to forecast DER power flows, including analyzing DER adoption and operational patterns and reviewing DER-related circuit demand changes over time. DER forecasting includes real-time, day-ahead, week-ahead, etc. forecasting to predict net power flow conditions in order to plan appropriately and optimize available grid resources. DER forecasting also includes developing long-term DER power flow forecasts to improve electric system planning accuracy. 2. DER Value and Solutions Analysis: DER value analysis refers to estimating the timeand locational-value of DERs. DER values should reflect the benefits DERs provide, including their potential distribution capacity deferral value, as well as the cost of reliably integrating them with the electric system. As referenced in DSPx, “The avoided cost of these [] distribution investments form the potential value that may be met by sourcing services from qualified DERs, as well as optimizing the location and timing of DER adoption on the distribution system to eliminate impacts and achieve least cost outcomes.” 7 DER solutions analysis refers to assessing the potential for DERs to defer traditional upgrades to the distribution system. 3. Circuit Modeling: Circuit modeling refers to the representation of real-time and forecasted distribution circuit topology, asset details, load and DER connections, and electrical connectivity (electric system configuration) required to run analysis and simulations for electric system planning and grid operations. 4. Sensing and Measurement: Sensing refers to the data collection from devices that measure, track, and record electrical information such as voltage, current, real power, reactive power, and frequency as examples. Measurement refers to the ability to record, track, and compare data to physical reference points in order to understand and determine the current state of any aspect of the electric system. This assists both with real-time grid operations and informs future electric system planning activities. 6 More information on DOE’s DSPx can be found at 7 U.S. Department of Energy, Office of Electricity Delivery and Energy Reliability, Modern Distribution Grid, Volume I: Customer and State Policy Driven Functionality, p. 53.
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5. Data and Device Communications: Data refers to various information that is provided by the field devices, including sensors referenced above, to the various software systems for near real-time use or for planning purposes. Device communications refers to the physical infrastructure that transports data to (and takes it from) field devices (e.g. the FAN and WAN). 6. Distribution Grid Control and Feedback: This refers to the ability to monitor electric system conditions in near real-time, and to use near real-time data to optimize grid resources devices and electric system configuration by controlling distribution grid assets (including DERs). As described in DSPx under Distribution Grid Controls, coordination and control refers to the signaling and mobilization of distribution grid assets and DERs providing grid services (directly or through an aggregator) to meet system operational and reliability goals on a dynamic basis. Goals include optimizing distribution system performance, and maximizing DER benefits, while maintaining or improving safety and reliability. 7. Reliability Management: Reliability management refers to the use of near real-time grid data, communications, processes, systems, and procedures to operate the grid safely and reliably. This enables distribution operators to prevent, discover, locate, isolate, and resolve power outages in an informed, orderly, efficient, and timely manner. Technology in this area encompasses many of the grid modernization software and field technologies working in concert, including the Grid Management System, communication infrastructure to transfer data, and the field devices being monitored and operated to ensure optimized grid configuration. 8. Cybersecurity: As referenced in DSPx, “Cybersecurity is the protection of computer systems from theft or damage to the hardware, software or the information on them, as well as from disruption or misdirection of the services they provide. It includes controlling physical access to the hardware, as well as protecting against harm that may come via network access, data and code injection, and due to malpractice by operators, whether intentional, accidental, or due to deviation from secure procedures.” 8 Modernizing the grid increases the number of devices an attacker might be able to exploit. New grid applications must be designed with improved cybersecurity controls throughout their lifecycle by integrating strong access controls, secure communications, and secure programming code. Cybersecurity needs to be integrated into each grid modernization component throughout its lifecycle to provide a strong framework against a cyber-attack. D. System-wide v. Local Investments 1. System-wide investments: System-wide investments provide foundational capabilities that are necessary for enabling all locational grid modernization investments to realize their full benefits. System-wide investments are required to meet the needs of the entire 8 U.S. Department of Energy, Office of Electricity Delivery and Energy Reliability, Modern Distribution Grid, Volume I: Customer and State Policy Driven Functionality, p. 57.
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distribution system, which include safety, reliability, and DER integration. These investments primarily include communication systems and software systems that enable greater visibility to grid operators for real-time grid monitoring and control. These investments also help electric system planners to better model and forecast the needs of the electric system. 2. Local investments: Local investments include field equipment installed on the distribution system to meet an identified or forecasted location-specific grid need including, but not limited to, safety and reliability needs or the integration of DERs (e.g. communication equipment for DERs that can be dispatched such as energy storage). E. Distribution System Management Activities 1. System Planning: Distribution system planning involves determining future grid needs based on reviews of historical data, forecasting, electric system capacity analysis, and information sharing activities. These functions require software and analytic tools to analyze historical electric system performance, model electric system topology and equipment, and perform forecasted load flow analysis for the distribution grid. System planning will leverage increasing amounts of granular field data to analyze past, present, and future network models to make accurate decisions about future infrastructure needs while incorporating expected DER performance into safety and reliability analysis to optimize future grid configuration. 2. Grid Operations: Grid operations technologies enhance operational capabilities to continually assess, monitor, and analyze near real-time data at various circuit locations to manage grid equipment and resources, including DERs, to improve reliability and optimize DERs for customers’ and the grid’s benefit. Grid operations requires granular visibility of electric system conditions and the ability to reconfigure the distribution grid and dispatch resources. Sensing and monitoring technologies are used to improve visibility of DER performance and the grid’s response to changing power flow and outage conditions. Communications technologies transmit this data, allowing grid operators to optimize asset utilization in near real-time. Distribution grid operations technologies encompass both field equipment and software. Field equipment is installed to meet safety and reliability needs in specific locations. Software, including operational forecasting, asset optimization, and distribution system models, are foundational functionalities required to perform grid operations with or without high DER penetration. 3. Market Operations: Markets support the provision of grid services for reliably serving load in a manner that maximizes value and minimizes costs while pursuing state policy objectives. Markets currently enable the realization and quantification of the energy and capacity benefits that DERs can provide to the bulk electrical system by enabling the sale of energy, ancillary services, and resource adequacy products to the bulk electrical system. Market opportunities for DERs at the distribution level are currently under development, largely within the Energy Storage MUA, DRP, and IDER proceedings, with the aim of quantifying and monetizing the local distribution grid benefits that DERs may provide. These distribution markets are expected to promote greater transparency for
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market participants by identifying locations where DERs could provide the greatest potential benefits, thereby promoting the optimal deployment and dispatch of DERs to satisfy local distribution grid needs, while simultaneously supporting system energy needs. Ultimately, robust market operations are necessary to enable DER benefit stacking. This is necessary to maximize the value DER can provide to the grid, thereby accelerating DER adoption and improving customer choice. Market operations technologies refer to a suite of integrated software and systems that collectively provide the grid operator with tools and information necessary to optimally dispatch available grid resources. The technologies enable markets to function effectively by incorporating numerous data (demand and behind-the-meter DER forecasts, participating generating resource bids, current grid conditions, planned outages, etc.), to develop optimal, least-cost resource dispatch schedules aimed at maintaining grid reliability. The current ISO market environment determines the dispatch of generating facilities, but future distribution markets could potentially inform the optimal dispatch of not only generation resources, but also distribution grid assets. This would expand leastcost dispatch for reliability purposes to an entirely new suite of electrical assets. The technologies required to enable these market functions include, but are not limited to, forecasting models (to predict load and non-dispatchable generation), power flow models (to determine grid needs, grid constraints, and the ability of DER capacity to contribute to grid needs), advanced distribution management systems (to provide forecasted and realtime grid condition information), distributed sensing devices (to provide locationalspecific information on real power, reactive power, power flow direction, and voltage), aggregation systems (to bundle DERs into meaningful resource clusters for dispatch), outage management systems (to account for grid and asset outages and reduced availability), web portals (for publication of prices, market information, and grid conditions, and to enable energy market participation and capacity auctions), optimization engines (to calculate optimal, least-cost dispatch while maintaining reliability despite grid constraints), distributed energy resource management systems (to monitor and dispatch DERs), communications systems (to monitor and pass instructions to generating facilities), advanced metering infrastructure (to measure resource performance), settlements systems (to compensate generators), and market monitoring (to assure fairness for all market participants). Many of these systems are “back office” systems deployed for system-wide use. Most of these systems may be deployed in the field or at substations, and thus could be deployed in stages to different locations. However, within a deployment region, all systems must be fully deployed to enable market operations in that region. Ultimately, to maximize effectiveness, these software and field equipment technologies will need to be deployed system-wide. F. List of Potential System/Integration Challenges General Issues 9 Description Examples are not limited to those procured by utilities. Grid Modernization Technologies to Mitigate Challenge 9
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Functional Group 1. Voltage Fluctuation 10 Distributed generation resources may be randomly intermittent, such as cloud covering a solar panel, thereby lowering their power production and impacting power quality (PQ). This intermittency causes voltage fluctuations and as a consequence, potential flicker in the form of a quick momentary voltage violation. Distribution Grid Smart Inverters, Operations Energy Storage, Substation LTCs, Grid Sensors 2. SteadyState Voltage Violations 11 Steady-state voltage violations may result from distributed generation injecting real power into the circuit, whereby voltage increases. It may also result from loads connecting to the circuit, whereby it decreases voltage. DERs may consequently cause nearby voltages to go above or below set voltage standards, which could damage electrical equipment and impact surrounding customers. This is a particular problem for situations where DER generation exceeds load and produces reverse power flow, which various utility equipment was not built for. Distribution Grid Operations, Distribution System Planning Smart Inverters, Load Tap Changers, Voltage Regulators, Capacitors 12, Communication 10 To address voltage issues, utilities have traditionally used voltage regulators, capacitors, and load tap changers. Smart inverters represent a new remedy for managing the voltage concerns at the source of the issues. Smart inverter functionalities, such as the Volt/VAR and fixed power factor functions of the Smart Inverter Working Group’s Phase 1 Recommendations, continue to evolve and may become a preferred method for voltage management over traditional approaches in the near future. 11 Edited from “Sustained Voltage Violations” to “Steady State Voltage Violations” Starting in 2011, the California Public Utilities Commission initiated an effort to review and, if necessary, revise the rules and regulations governing the interconnection of generation and storage facilities to the electric distribution systems of the investor-owned utilities also known as Electric Tariff Rule 21. As part of this effort, the CPUC and the California Energy Commission established the Smart Inverter Working Group (SIWG) to take advantage of the rapidly advancing technical capabilities of 12
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Systems 13, Grid Management Systems, Energy Storage, Reconductoring, Reconfiguration or Addition of Circuits, Remote Switching, Grid Sensors, Energy Storage and Controls 3. Masked Load Masked load refers to the load on a circuit that is served by customer-sited generation and to which the grid operator lacks real-time visibility. Realtime load data for an entire circuit is available to the operator at the substation. On circuits without DERs, this load data is sufficient for operators to estimate load levels along the circuit. On circuits with DERs, however, load is offset by the DER generation, and the operators only see the net load (gross load minus the DER generation). While telemetry at the customer site provides limited real-time generation information, load information from AMI is not available in real-time. So, from the operator’s perspective, some load is Distribution System Planning, Distribution Grid Operations Sensors, Grid Management Systems, Communication Systems, Smart Inverters, More granular DER production information, Remote Switching, Grid Sensors, ShortTerm Load-DER Forecasting inverters. Inverters are required by some generating resources to convert the direct current (DC) from the generating resource to the voltage and frequency of the alternating current (AC) distribution system of the IOUs. Phase 1 refers to the first set of recommendations of the SIWG, which were also known as the autonomous functions. 13 Communication Systems may include 3rd party communications infrastructure and does not predetermine the communication systems are utility-owned
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4. Thermal 14 masked by DER generation such that the operator is unaware that it exists. This limits the grid operators’ situational awareness which could limit electric service reliability. Power flow exceeding device ratings due to the bi-directionality of power flow. This includes power flow stemming from load in one direction and power flow stemming from distributed generation in the opposite direction. This two-way power flow may result in wires and/or transformers exceeding their thermal limits since they were designed for one-way power flow. Distribution Grid Operations, Distribution System Planning Substation and Circuit Upgrades, Re-Conductors, Voltage Conversion, local DERMS, Communication Systems, Grid Sensors, Grid Management System, Energy Storage, Remote Switching 5. Protection Protection systems were designed to respond to abnormal conditions when subjected to specified benchmarks. DERs may create coordination problems with other protection devices, thereby producing a safety risk or creating an unintended additional risk outage. Distribution System Planning, Distribution Grid Operations Relays, Grid Management Systems, Automation, Communication Systems, Grid Sensors, Remote Switching 6. Operational Limitations Abnormal conditions or normal operation with or without DERs may create operational flexibility problems in maintaining reliability and/or increase the maintenance of distribution equipment due to operation outside of design parameters, such as load tap changes due to voltage variations or continuous loading of secondary transformers that are intended to have a cooling period overnight. Distribution System Planning, Distribution Grid Operations Technology Platforms, Sensors, Automation, Grid Management Systems, DERMS, Communication Systems, Smart Inverters, Remote Switching, Grid Sensors 14 Technologies that increase the thermal limit of nodes on the system are generally legacy technologies. New substations and circuits, re-conductors, and voltage conversion are all possible. Some DERs may also be used to minimize the potential of reaching the thermal rating of equipment. For instance, energy storage may lower the peak of the net demand on a circuit and allow more distributed generation to interconnect.
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7. Fault Location and Service Restoration 8. Energy Market Security 9. Cybersecurit y Utilities are already moving toward automated schemes that restore service more quickly following a fault. These same schemes will also allow some customers to avoid experiencing an outage altogether. With increasing adoption of DERs utilities’ grid operations methods need to consider the variation and intermittency of variable resources. This should include considering the output of these resources when determining switching operations to avoid potential operating constraint violations (to avoid a fault). It should also include considering these resources when determining the appropriate switching operations to restore service to as many customers as possible following a fault. The market could be manipulated by a participant with sufficient market power. Market monitoring capabilities are required to provide the tools needed to identify and mitigate security issues, such as insecure market participant transactions. Distribution System Planning, Distribution Grid Operations Automation, Sensors Technology Platforms, Grid Management System, Communication Systems, Grid Sensors, Remote Switching Distribution Grid Operations, Distribution Market Operations Technology Platforms, Sensors, Resource Diversity, Grid Management System, Sensors The proliferation of DERs that Distribution Grid communicate with utility systems Operations presents many more opportunities and vulnerability to cyber threats. This includes DER devices large enough, that if used incorrectly, could damage distribution equipment on the system particularly in ways difficult to restore. Technologies that can Enable IP Based Cybersecurity Protocols, CSP, Substation Automation, FAN, Grid Management System
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10. DER Aggregation Impacts on the Bulk Grid In a world of increasing DERs and customers, the larger grid needs to be able to handle events that occur which could lead to devices reaching their thermal limits causing cascading outages and grid blackout. These events need to be mitigated in the planning and operation stages to accommodate the loss inertia in the system due to high inverter-based generation and a large installed base of DER which trips offline due aggressive protection settings (will be fixed in the future with smart inverters). Distribution System Planning, Distribution Grid Operations Communication Systems, Grid Management System, Smart Inverters, Synchronous Condensers, Static Var Compensators, Remote Switching, DER Headend, Grid Sensors, Curtailment, Negative Pricing, Flex Resources 11. DER Wholesale Market Participation Growth of DERs responding to wholesale energy and ancillary service market dispatches have the potential to create distribution level voltage and capacity violations without new tools and processes. Distribution System Planning, Distribution Grid Operations System Modeling, Short and LongTerm Forecasting, Grid Management Systems, DERMS, DER Headend, Communication Systems (END OF APPENDIX C)
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PG&E Gas and Electric Advice Filing List General Order 96-B, Section IV AT&T Albion Power Company Alcantar & Kahl LLP Anderson & Poole Atlas ReFuel BART Barkovich & Yap, Inc. Braun Blaising Smith Wynne P.C. CalCom Solar California Cotton Ginners & Growers Assn California Energy Commission California Public Utilities Commission California State Association of Counties Calpine Casner, Steve Cenergy Power Center for Biological Diversity City of Palo Alto City of San Jose Clean Power Research Coast Economic Consulting Commercial Energy County of Tehama - Department of Public Works Crossborder Energy Crown Road Energy, LLC Davis Wright Tremaine LLP Day Carter Murphy Dept of General Services Don Pickett & Associates, Inc. Douglass & Liddell Downey & Brand Ellison Schneider & Harris LLP Energy Management Service Evaluation + Strategy for Social Innovation GenOn Energy, Inc. Goodin, MacBride, Squeri, Schlotz & Ritchie Green Charge Networks Green Power Institute Hanna & Morton ICF International Power Technology Intestate Gas Services, Inc. Kelly Group Ken Bohn Consulting Keyes & Fox LLP Leviton Manufacturing Co., Inc. Linde Los Angeles County Integrated Waste Management Task Force Los Angeles Dept of Water & Power MRW & Associates Manatt Phelps Phillips Marin Energy Authority McKenzie & Associates Modesto Irrigation District Morgan Stanley NLine Energy, Inc. NRG Solar Office of Ratepayer Advocates OnGrid Solar Pacific Gas and Electric Company Pioneer Community Energy Praxair Regulatory & Cogeneration Service, Inc. SCD Energy Solutions SCE SDG&E and SoCalGas SPURR San Francisco Water Power and Sewer Seattle City Light Sempra Utilities Southern California Edison Company Southern California Gas Company Spark Energy Sun Light & Power Sunshine Design Tecogen, Inc. TerraVerde Renewable Partners Tiger Natural Gas, Inc. TransCanada Troutman Sanders LLP Utility Cost Management Utility Power Solutions Utility Specialists Verizon Water and Energy Consulting Wellhead Electric Company Western Manufactured Housing Communities Association (WMA) Yep Energy
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