Evolving Our Grid: System Planning and Grid Modernization

GRC Overview

October 24, 2016

Objective and Agenda

• Setting the stage: distribution system overview

• The evolving grid: drivers

• Grid modernization and reinforcement Programs

• Evaluating DER as cost effective alternatives

• GRC details: Grid modernization and reinforcement programs– Distribution Automation – Substation Automation– Communications – IT Software – Grid Reinforcement and 4kV Programs

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Today’s objective is to provide information and answer questions about our plan for evolving the grid as articulated in our GRC.

Setting the Stage: Distribution System Overview

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Substations consist of multiple circuits feeding a large area.  

This substation is comprised of 14 circuits, feeding over 13,500 customers.A circuit is fed from a single circuit breaker at a substation and feeds multiple transformers

This circuit feeds over 1500 customers utilizing over 150 service transformers.

Multiple meters could be fed by a single transformer

This transformer serves 8 customersThe service meter is the interconnection point between the utility and the customer

This feeds a single customer

Anatomy of a Distribution System

3

In a conventional distribution circuit, power flows in one direction from the substation to the customers’ load.

Overhead Distribution Circuits

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Open Switch

Switch toanother circuit

Closed switch

Circuit Breaker

Capacitor BankTransformer

Fuse

Today’s Distribution System

• Radial distribution design is reconfigurable

• Traditional operations are largely manual, based on predictable one-way flow of energy

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While the system may seem straight forward when we zoom in, in reality, there are many possible configurations and operational complexity.

Transmission NetworksThe transmission system is designed as a network to support

reliability relying on multi-directional power flow.

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SCE’s Electric Power System Components

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SCE’s Current Reliability

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The industry is seeing reliability improvement year-over-year in both the duration and frequency of outages while SCE’s reliability is flat to declining.

Today, SCE makes “traditional” grid investments to maintain reliability, not improve reliability• Replacement of aging

infrastructure (4kV, cable and conductor, substation equipment)

• Basic automation to facilitate restoration with substation level visibility and control of grid equipment

*WOP is “With Out Plan” or repair outageshttp://grouper.ieee.org/groups/td/dist/sd/doc/Benchmarking-Results-2015.pdf

2016 WOP* SAIDI

Existing Grid Operations are Based on Limited Visibility

OperationalRequirements Current Level of Visibility Supporting Equipment

Power flowvisibility andestimation

Three phase circuit and transformer loading at substation

SCADA (various technologies), RTUs, outage, distribution, and energy management systems

Fault location General fault location upon inspection, customer call, some smart meter analytics

“Manual” fault indicators, smart meter

Voltagemonitoring and status

1- phase distribution voltage 1-phase from capacitor banks or remote control switches, smart meter indication

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Limited number of fault indicators

Distribution System Limitations

• Distribution communication system will reach full saturation beginning in 2018– Additional automation after full saturation could lead to inaccuracies and

slow the system down– Technology developed 20 years ago

• Need granular visibility to advance our planning and operating capabilities– Current operations (voltage regulation), fault location based on estimation

methods

• Safety and reliability exposure– E.g., overstressed circuit breakers– Increased complexity to operate and switch distribution system circuits due

to variable and intermittent power flows

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The grid was not designed to meet the demands of today and the future.

The Evolving Grid: Drivers

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Key Drivers to Evolve the Grid

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State Energy and Environmental

Policy

Customer Choice and Reliability

Increasingly complex grid

Grid modernization supports state policy objectives to increase energy from renewables and decrease greenhouse gas emissions.

Customers have more choices and are increasingly adopting DERs and have higher expectations for reliability for their electronic-dependent lives.

As distributed resources are added to the grid, operating characteristics of the grid are changing leading to increased complexity.

“This traditional system was not designed to meet many emerging trends, such as greater adoption of relatively low inertia generation sources, growing penetration of distributed generation resources, and the need for greater resilience. As described in several recent studies, a modern grid must be more flexible, robust, and agile.” -- DOE Quadrennial Technology Review, 2015

Key Driver: Increasingly Complex Grid

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As distributed energy resources are added to the grid, operating characteristics of the grid are changing, leading to increased complexity.

• Peak Time for Distribution Circuits Load and PV do not typically coincide

• The grid needs to accommodate this available power for the benefit of the customer and the grid

• Shaded areas show 3-phase reverse powerflow and intermittent output from PV from an actual circuit, this appears as one-way flow to operators

• Operators need visibility to power flow magnitude and direction

Key Driver: State Energy and Environmental Policy

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2050

• Reduce GHG emissions to 40% below 1990 levels

• 50% of electricity sales from renewables

• Reduce GHG emissions to 80% below 1990 levels

• Reduce GHG emissions to 1990 levels

• 33% of electricity sales from renewables

• 1,325 MW of procured energy storage capacity by 2025

• Once through cooling• New residential construction

zero net energy

• New commercial construction zero net energy

• Double statewide energy efficiency savings

2030

2020Today

• 1.5 million electrical vehicles

2025

• Due to the size of SCE’s system, deploying the required technology will take 10 years to cover 60% of SCE’s total distribution circuits (urban circuits)

• SCE’s Grid Modernization Program can help meet the stated goals and objectives in the DRP within 10 years

Achieving our expansive energy and environmental policy goals will require taking foundational steps to evolve the grid.

Key Driver: Customer Choice and Reliability

• Electric Vehicles: 70,000 in SCE territory today; expect over 300,000 by 2020

• NEM Applications: In 2008, averaged 250 per month; in 2015, averaged 4,000-5,000 per month

• Federal tax credit increases customer incentives for DERs

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Customers Are Adopting DER Customers Need Reliable Service

• Modern society is increasingly more dependent on electricity

• 42% of customers in the West would not accept a two-day power outage, even if they were paid as much as $1,000 for it

• 64% of customers responded that power outages cause “really significant problems” for their households

• 71% of customers with income less than $40,000, said outages cause “really significant problems”

*Source: T&D World Magazine, Reliability Demand Survey Finds Many Americans Have Low Tolerance for Power Outages (May2012), available at: http://tdworld.com/smart-energy-consumer/reliability-demand-survey-finds-many-americans-have-low-tolerance-power-outage

Grid Modernization and Reinforcement Programs

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Grid Modernization Investments Work Together to Provide Multiple Benefit Streams Concurrently

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Enable DER integration and

adoption

Realize DER benefits

Enhance safety and reliability

Support customer technology and service choices

Enable opportunities to obtain value from DERs through wholesale and distribution grid services (e.g., distribution deferral)

Improve system reliability and outage restoration while supporting increasing levels of DERs and two-way flow of energy

We have taken a holistic approach to evolve our distribution design philosophy to most efficiently address changing expectations of the grid.

Grid Modernization Benefit: Enhanced Safety & Reliability

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63%

37%

18%

65%

39%

21%

0%

10%

20%

30%

40%

50%

60%

70%

(0, 0) (1, 1) (2, 2)

Number of existing mid and tie switches (Mid, Tie)

% SAIDI Improvement % SAIFI ImprovementImage source: U.S. Department of Energy Office of Electricity Delivery and Energy Reliability, (Nov 2014), Fault Location, Isolation, and Service Restoration Technologies Reduce outage Impact and Duration, Retrieved from https://www.smartgrid.gov/document/fault_location_isolation_and_service_restoration_technologies_reduce_outage_impact_and.html

The changing operating conditions of the grid requires increased automation, communication, and analytic capabilities.

Expected reliability improvements realized through adding three mid-point and three tie switches to distribution circuits.

FLISR reduced the number of customers interrupted by up to 45%, and reduced the customer minutes of interruption by up to 51% for an outage event.

Results from SCE 2016 Study

Grid Modernization Benefits: Enable DER Integration and Adoption

• Proactively remove forecasted constraints due to voltage, thermal, and protection limitations

• Timely information updates to reflect grid changes

• Leverages collected field data to improve models to maximize integration capacity

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Number of Installations MW Installed

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Transparent, actionable information on available capacity and benefits in specific locations enables customers and developers to better forecast

costs and can help to fast-track interconnection.

Monthly Installations and MW Installed in SCE

(installations less than 1 MW)

Grid Modernization Benefits: Realize DER Benefits

Image source: http://www.solarcity.com/company/distributed-energy-resources

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New capabilities are needed to create opportunities for DERs to increase efficiencies, defer traditional infrastructure investments, and facilitate DER

ability to achieve wholesale value.

Traditional capital upgrades result in additional operating margin

Leveraging DERs as solutions will require granular monitoring and control due to

reduced operating margin

Grid Modernization Enables Capabilities in Three Categories Needed to Realize Benefits

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Leverage increased amounts of field data to analyze past, current and future network models to make accurate decisions about future infrastructure needs and incorporate the effects and expectations of DERs.

Enhance operational capabilities to assess, monitor, analyze, and manage grid resources including DERs to enable quick responses to outages and optimize DER for customer and grid benefit.

Help transfer field data and connect substations and grid resources to enable analysis and support decision-making in the needed timeframes.

Foundational capabilities are enabled by the collection of grid modernization elements working together.

Communications

Planning

Operations

Operations Capabilities

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Operations enhancement will provide more granular visibility to system conditions, and the ability for system operators to reconfigure

the distribution grid and dispatch resources.

Communications Capabilities

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Communication systems must be secure, require larger bandwidth and low latency to support needed data transfer for timely, quality decisions.

FieldArea

Network

Wide AreaNetwork

DERProviderNetwork

Secure Gateway

Planning Capabilities

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Planning tools will enable forecasting, analysis, and sharing.

Load GrowthNeed

Hosting Capacity

Need

Reliability & Operational

Need

Identify Optimal Locations

System Analysis External Communication

Optimal Grid SolutionsGrid Analytics

Capacity AnalysisVoltage Analytics

Determine optimal solutions

Load and DER Forecasting

Long Term Planning Tools DRP External Portal

Grid Interconnection Processing Tool

Historical Load Profiles

Substation/Circuit Time Series Profile

Forecasts

Outage Analytics

System Modeling Tool

StreamlinedInterconnection

Present Information Online

Load & DER Growth Develop Wires Solutions

Long Term Planning Tools

Grid Analytics Applications

• Integrated• DER growth• Base growth

Grid Modernization and Reinforcement Elements• Automation: Adding distribution and substation technology to gather data,

monitor, and manage grid resources in real time

• Communications: Upgrading communication networks, such as expanding the fiber optic and field area networks to support timely data transport

• Technology Platforms: Developing improved analytics platforms for planning, operations, outage management, interconnection, and transparency for customers

• Grid Reinforcement, 4kV Systems: Updating infrastructure to address capacity, reliability, and equipment obsolescence

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Grid Reinforcement; Remove 4kV1

1

2

3

4

4

3 2

Evaluating DER as Cost Effective AlternativesTraditional Infrastructure Deferral Pilots

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Grid Modernization Benefits: Deferral Pilot

SCE proposes a pilot to evaluate the potential deferral of eight load growth projects by using DERs in concert with a modern distribution system• Analyze deferral opportunities across a range of characteristics including climate zone,

customer and geographic diversity, and DER performance in concert with grid modernization

• Results will inform how DERs can be integrated into SCE’s planning criteria in a safe, reliable, and effective manner

• Potentially refund to customers the revenue requirement associated with the approximately $40 million capital request in this GRC

Test whether DERs can have a measurable impact on transformer life. • Determine loading characteristics and portfolio of DERs that would be required to extend

the life of a transformer• Results of this pilot will help show whether DERs can provide life extension benefits to

transformers

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The capabilities realized through grid modernization will help enable opportunities for DERs including the opportunity to

defer traditional infrastructure projects.

Grid Modernization and Reinforcement GRC Details

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4a Grid Reinforcement

4b 4kV Systems

1a Distribution Automation

1b Substation Automation

2 Communications

3 IT Tools

Grid Modernization and Grid Reinforcement Programs

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$21 $117

$392 $408 $417

$8

$23

$60

$128 $147

$10

$37

$70

$78 $59

$152

$197

$275

$292 $233

$0

$200

$400

$600

$800

$1,000

2016 2017 2018 2019 2020

Nom

inal

($M

)

Automation Communications IT Tools Grid Reinforcement and 4kV

Increasing situational awareness with more near real-time telemetry data points throughout the circuits that help identify issues quickly and accurately

Facilitating remote isolation and restoration, decreasing outage duration and area of impact

Increasing operational flexibility with appropriately-sized line sections for circuit switching, which will minimize de-energized sections during planned and unplanned outages

1a. Distribution Automation

Definition

4a1b 32 4b

SCE’s Distribution Automation effort improves on the historical circuit automation program by installing automatic switches, sensors and circuit connections:

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1 2 3

A fault occurs downstream of the mid-point RCS.

Half the customers (Group A and B) will experience a momentary outage.

Half the customers (Group C and D) will experience a sustained outage.

The same fault occurs downstream of the mid-point RCS. Group A customers do not experience any interruption because RIS a is able to immediately detect, isolate, and interrupt the fault.

Half of the customers will be restored momentarily. Power will be restored to Group B through Sub A and to Group D through Sub B.

Group C will experience a sustained outage.

Configuration Scenario

4a32 4b

Open Switch

Closed Switch

Fault

RCSRemote Controlled Switch

Circuit Breaker

Substation

Energized Line (Arrow Shows General Direction of Flow)

Not Energized Line

RISRemote Intelligent Switch

No Outage

Momentary Outage (< 5 mins)

Outage

Grid Modernization Distribution Automation (after switching)

Historical Distribution Automation (after switching)

1a. Distribution Automation 1b

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4a3

Necessity

Substation

Load: Load:

Generation:

Perceived Load:

?

Challenges:Inability to monitor equipment loading throughout the circuit.

Impaired ability to switch/transfer loads between circuits.

Erosion of current reliability from impaired ability to restore power following faults.

Challenges:Opportunity for improved reliability from ability to transfer smaller loads off of faulted circuits.

Opportunity for greater for DER utilization.

2 4b

Substation A

Load: Load: Load:

Substation B

Load:

1a Distribution Automation 1b

Masked Load Transfer Load

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Scope & Deployment

4a32 4b1a Distribution Automation 1b

• New circuit design consists of 3 mid-point switches, 3 circuit ties– Allows for manageable load blocks for reconfiguration (~100A)– Minimizes customer impacts due to outages– Provides necessary data to inform current state power flow

• Remote fault indicators are strategically deployed along circuits at tap lines and branches to optimize fault location (~10 per circuit)

• Augmenting 200 WCR circuits with automation each year 2018-2020

• Full automation of 88 DER-directed circuits each year 2018-2020; locations selected to:

– Facilitate capital deferral pilots– Mitigate high penetration of DERs (4 or more circuits with reverse power flow from

same sub)– Realize potential DER benefits (high asset utilization)

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Cost

4a32 4b

Methodology:Cost forecasts were calculated by multiplying the number of Non-WCR Circuits Receiving Full DER Enabling Automation and WCR Circuits Receiving Augmented Automation against their respective unit costs:

• Non-WCR: Full DER Enabling Automation Unit Cost x Number of Non-WCR Circuits• WCR: (Full DER Enabling Automation Unit Cost – WCR Non-Augmented Automation

Unit Cost) * Number of WCR Circuits

1a Distribution Automation 1b

Distribution Automation Full Deployment

Year

WCR Circuits Receiving Augmented

Automation

Unit Cost(Nominal,

$000s)

Non-WCR Circuits Receiving Full DER

Enabling Automation

Unit Cost(Nominal,

$000s)

Total Forecast Spend

(Nominal, $000s)

2018 200 $ 907.3 88 $ 1,087.6 $ 277,168 2019 200 $ 935.8 88 $ 1,121.7 $ 285,863 2020 200 $ 965.5 87 $ 1,157.4 $ 293,795

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Benefits

4a1a Distribution Automation 1b 32 4b

• Enables improved system reliability and outage restoration while supporting increasing levels of DERs and two-way flows of energy:

– Reliability improvement is measured by customer minutes of interruption (CMI) and the customer’s cost per CMI:• Reduction of 23 million CMI and 167,000 customer interruptions (CI) in 2019 on WCR circuits• Reduction of 1.3 million CMI and 15,000 CI in 2019 on focused circuits.

From the customers’ perspective, the resulting reduction of 24 million CMI at a value of $2.321 per averted CMI in effect pays for the grid modernization investment in less than 5 years• Enables increasing DER adoption by addressing otherwise limiting factors for hosting

capacity caused by masked gross load and supply resources (e.g., DG & energy storage).

• Enables optimal use of DER resources by customers and for CAISO and distribution grid services by managing constraints through circuit reconfigurations – which is the most effective & efficient means to manage distribution constraints.

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1 Based on “Southern California Edison Customer Interruption Cost Analysis” performed by Nexant

4a1a 1b Substation Automation & Common Substation Platform (CSP) 32 4b

Definition

SA-3: Control system for substations which will enable remote control of and data acquisition from substation equipment.

CSP: Computing platform (hardware and software) which will serve as the communication and control hub between the operations center and the substation equipment and distribution circuit equipment and sensors.

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4a32 4b

Necessity

1a 1b Substation Automation & CSP

SA-3:Existing RTUs and SAS-1 systems are aging and approaching end of life, unsupported by manufacturers, cyber-insecure, limited remote control capabilities, and cannot support remote resetting of circuit breaker trips.

CSP: Distribution Automation enablement:

• DA switches and telemetry will require a cyber-secure communication link to the operations control center.

• Optimal performance of grid and DER devices will require distributed intelligence.

SA-3 enablement:• SA-3 will require a cyber-secure communication link back to the operations

control center.

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4a32 4b

Scope & Deployment

396 substations will be upgraded over the next ten years based on locations where multiple circuits will be automated.

Of these:• 320 currently have only SAS-1 or RTU levels of

automation and will receive both SA-3 and CSP. • 76 currently have SAS-2 level of automation

and will only receive the CSP component to enable cybersecurity functionality.

Deployment of the Substation Automation plan will occur in two phases:

1) a small scale deployment in 2017, to validate system capabilities, and

2) full deployment from 2018-2020 of approximately 30 SA-3 systems per year on average.

A prioritization process will target those substations where both capacity constraints exist and DERs can provide grid benefits.

1a 1b Substation Automation & CSP

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4a32 4b

Benefits

1a 1b Substation Automation & CSP

• The CSP will provide the communication link from DA switches and telemetry necessary to ensure future DERs do not erode current level of reliability.

• The CSP will provide distributed intelligence necessary to realize improved reliability from enhanced DA switching capabilities.

• The CSP will provide modern cybersecurity.

• SA-3 will improve safety by enabling prompt adjustment of relay trip settings following circuit realignments.

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4a1a 3 4b1b 2 Communication

Definition

FAN: Modern radio system allowing distribution automation switches and sensors to communicate with one another and the substation.

WAN: Expansion of existing fiber optic cable system between operations control centers and substations.

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4a1a 3 4b1b 2 Communication

Necessity and Benefits

NetComm Utilization• Existing NetComm radio system

(now 20 years old) currently has a typical command cycle time of two minutes.

• The NetComm system will be impacted due to inadequate speed and capacity.

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FAN:• Will enable the connection of over 250,000 distribution devices, with a device-to-device

latency of less than 100 milliseconds and an overall latency of less than 15 seconds.

WAN• Data transmission speed and volume demands expected with future DERs, DA, SA-3,

and CSPs, need to be supported with fiber optic communication between substations.

4a1a 3 4b1b 2 Communication

Scope & Development

FAN Deployment Plan

A failure-resistant “mesh” network only works with other radios nearby.

This “mesh” requirement mandates deployment by geographical area.

WAN Deployment Plan

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These 531 miles of fiber will connect 42 substations. Connecting all substations requiring fiber will require an additional 252 miles beyond this GRC cycle.

* Fiber terminal upgrades are needed because the existing fiber terminals, designed for lower speed SCADA and protective relaying circuits, will not support the high speed requirements of SA-3 and FAN.

3 IT Tools – SMT / DRP EP 4a1a 4b1b 2

The System Modeling Tools (SMT) leverages power system modeling for engineering analysis of the distribution grid.

Distribution Resource Plan External Portal (DRPEP) is an interactive web portal that publishes analyses results.

• Enables batch power flow, short circuit duty, transients, protection coordination, harmonics, capacity optimization

• Public has immediate web access to information/data regarding circuit interconnection capacities.

• Provides DER ICA on every line section and node

• DER owners or operators can upload DER data

• Publishes LNBA results

What ?

Current software tools used for analyzing capacity require significant manual efforts that rely upon conservative assumptions which limit precision.

• Customers face long delays in obtaining responses and results for feasibility requests to connect DERs

• Engineering analyses employs conservative assumptions,

• Forecasted growth in application submittals increases time required for interconnection review

• SCE system information published in DERiM is updated only monthly. Dated information can misinform customers’ interconnection decisions

Necessity

DER adoption is encouraged by improving SCE processes that calculate and publish system planning and interconnection data such as ICA

• Accurate assessment of DER siting opportunities is improved through granular understanding of load and available capacity throughout the grid

• Enables web based, interactive tools to support data interrogation, analysis, and download

• Interconnection process unhindered by conservative modeling assumptions and with minimal delay.

• Greater precision is streamlined to perform power system analyses on SCE electrical system

Benefits

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3 IT Tools – SMT / DRP EP 4a1a 4b1b 2

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System Modeling Tool

Scope & Development

DRP External Portal

3 IT Tools – GMS 4a1a 4b1b 2

SCE’s Grid Management System (GMS) is an advanced software tool that will receive and analyze real-time information on customer energy usage, power flows, outages, faults and micro-grid status.

• Interface between operators in the control centers and grid assets to facilitate operations in response to or in preparation for grid events

• Enhanced reliability, optimization, operational, DER, and infrastructure management applications that include a heightened level of intelligence and control necessary to effectively manage an increasingly complex distributed grid.

What ?

With DERs being connected to the grid, operators have been given a fourth responsibility – optimize the benefits of DERs.

• Limited information available to the operator about distribution circuitry and limited level of control an operator has over the circuit.

• Increased adoption of DERs increases grid management inadequacies that will not allow:a. Power flow optimization

including DERsb. Distribution system situational

awarenessc. Protection re-config with

dynamic settingsd. Integrated switching

management

Necessity

The GMS will provide safety and reliability benefits and support the realization of DER Potential

• Limits the extent and duration of unplanned outages

• Enables effective switching management

• Provides distribution system situational awareness

• Provides actionable information and recommendations to system operators

• Enables reconfigurable protection to support public and worker safety and avoid equipment damage

• Optimizes system power flow and leverages DERs

Benefits

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3 IT Tools – GMS 4a1a 4b1b 2

Scope and Development

Phase 1:• Integrate existing DMS and OMS functions and enhance with required GMS functions that include the following: real-time situational awareness and analysis, operational planning, DER management, and infrastructure management functions. Target completion in 2019.

Phase 2: • Build upon previous phase in introducing complex grid management functions to manage and optimize DERs to utilization and enhance grid reliability. This phase includes functions such as power flow optimization, reconfigurable protection, micro-grid management, and a comprehensive training simulator to support organization readiness of the new grid management functions. Target completion in 2020.

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3 4a Grid Reinforcement1a 1b 2 4b

Grid Reinforcement Programs

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• Distribution Circuit Upgrades– Covers short term upgrades needed to solve distribution needs that arise due to

increased demand• Mitigation of overloads• Facilitate load balancing• Proportional to the amount of system wide annual load growth

– Work types covered• Installing new switches• Upgrading sections of cable or conductor• Installing to conductor to create circuit ties

– Additional drivers• DER-driven upgrades

• DER IEPR forecast at the circuit level identified overloads on specific circuits• Assumes smart inverters can self-regulate and correct voltage problems• Assumes even distribution of DERs (not clustered)

• Substation Equipment Replacement SERP covering overstressed circuit breakers

• 4kV Upgrades– Cutovers and eliminations

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• SCE’s current forecasts require additional grid upgrades to integrate DERs forecast for 2020*

– Over 80 miles of reconductor needed (voltage, thermal, or protection limits exceeded)

– Over 50 circuit breakers will need replacement for safety reasons (fault current exceeds breaker rating)

– Over 11 additional 4kV substations estimated to experience reverse power flow which inhibit the adequate operation of these substation

• The identified grid upgrades will insure that DERs can continue to be connected to the distribution system while maintaining system safety and reliability

• The required additional scope was identified by taking into account existing system conditions (system ratings and DER) and DER projection to 2020*

* Based on preliminary analysis of updated DER growth scenarios

3 4a Grid Reinforcement1a 1b 2 4b

• 4kV Programs include cutovers (since 2006 GRC), and eliminations (since 2015 GRC)

• Program Drivers– Aging infrastructure– Operational flexibility constraints– Operation and maintenance constraints– Need for expansion and space constraints– Insufficient capacity– Forecasted reverse power flow

• Alternatives– Run to failure– Manual load curtailment– Rebuild existing substation– Partial cutovers

3 4a1a 1b 2 4b 4kV Systems

4kV Elimination Program

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• Approximately 20% of SCE’s circuits are 4kV, serving mostly older residential neighborhoods

– Approximately 26% of SCE’s customers are in disadvantaged communities– Approximately 44% of customers in disadvantaged communities are on 4kV circuits

• Greater than 50% were installed over 50 years ago

• 4kV Cutovers are intended to mitigate significant overloads– Thermal– Unbalance and ground protection

• 4kV elimination removes aging substations and circuits and converts to available 12 and 16kV facilities

• 4kV circuits have lower load and DER capacity

• Approximately 20% of SCE’s 4 kV substations are completely “islanded”– There is no ability to pick up load during planned or unplanned outages

• The overall cost of providing energy at 4 kV is higher than either 12 kV or 16 kV due to higher losses at the lower voltage

3 4a1a 1b 2 4b 4kV Systems

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Many 4 kV substations are in space constrained areas, limiting the possibility of expansion

3 4a1a 1b 2 4b 4kV Systems

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Wrap-up

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Grid Modernization is Essential to Evolve the Grid to Support Our Customers and Achieve State Goals

• The grid has and continues to change as technologies evolve and customers utilize the grid in expanding ways

• Different operational conditions are emerging that require capabilities the current grid and utilities need to evolve and develop

• The ability for customer-owned DERs to provide distribution and transmission grid operations requires tight coordination between the DER operator, the utility, and the ISO to ensure reliability and confirm DER performance for compensation

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SCE looks forward to additional opportunities to discuss and clarify our grid modernization and reinforcement plans.

Thank you

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