Evolving Our Grid: System Planning and Grid Modernization GRC - - PowerPoint PPT Presentation
Evolving Our Grid: System Planning and Grid Modernization GRC Overview October 24, 2016 Objective and Agenda Todays objective is to provide information and answer questions about our plan for evolving the grid as articulated in our GRC.
– Distribution Automation – Substation Automation – Communications – IT Software – Grid Reinforcement and 4kV Programs
1
2
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
transformers. Multiple meters could be fed by a single transformer This transformer serves 8 customers The service meter is the interconnection point between the utility and the customer This feeds a single customer
3
4
Open Switch
Switch to another circuit
Closed switch Circuit Breaker Capacitor Bank Transformer Fuse
based on predictable one-way flow of energy
5
While the system may seem straight forward when we zoom in, in reality, there are many possible configurations and operational complexity.
The transmission system is designed as a network to support reliability relying on multi-directional power flow.
6
7
8
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
infrastructure (4kV, cable and conductor, substation equipment)
facilitate restoration with substation level visibility and control of grid equipment
*WOP is “With Out Plan” or repair outages http://grouper.ieee.org/groups/td/dist/sd/doc/Benchmarking-Results-2015.pdf
2016 WOP* SAIDI
Operational Requirements Current Level of Visibility Supporting Equipment Power flow visibility and estimation 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 Voltage monitoring and status 1- phase distribution voltage 1-phase from capacitor banks or remote control switches, smart meter indication
9
Fault Indicators
2 4 1 3 S 2/ 0 2 / 2 / 0 2 / 0 2/ 0 2 / 0 2/ 0 2/ 0 2 / 0 2/ 0 2 / 2 / 0 2 / 0 2 / 0 2 / 0 2 / 0 2 / 2 / 0 2 / 0 2 / 0 2/ 0 2 / 0 2 / 2/ 0 2 / 0 2 / # 2 # 2 # 2 # 2 # 2 # 2 # 2 # 2 #2 #2 #2 # 2 # 2 # 2 # 2 # 2 # 2 # 2 # 2 # 2 # 2 # 2 #2 # 2 #2 # 2 # 2 2 1 3 1 R A G 2 3 R T L V 5 12 42 4 0 RCS5 9 04 POS 1 1 3 2 1 2 4 3 R A G R T L 2 1 3 1 9 1 1 4 18 00 P 5 5 8 6 4 8 6 A 600A FI 05 008 POS.3 FI 05 2 4 5 POS.1 FI 05 032 POS.4 MARI POSA THORNWOOD E L M W O O D N I G H T H A W K L AKESI DE MI DDL E SCHOOL M5142280 V 5 084 580 GS547 4 PENCE SANTIAGO B514 4616 H5 144615 B512 5598 B514 1865 B5141866 H5144613 B5 141864 B5141863 B514186 2 B512559 9 B5 125600 B512 5597 S512 4247 H5144614 S5124 247 BS0544 B5142974 S5124247 BS1576 B5 125595 B512 5596 BS1288 S5 125415 BS128 7 B5 143227 B5143226 B5125 413 B5143225 B512 5189 B5125190 B512 5192 B5144 612 X5125188 B5125073 B5125 191 B5125193 B5 125354 V 512 4243 GS0948 BS12 04 S5124242 BS09 46 B5143224 BS589 1 B512 5137 B512 5194 B512519 5 B512 5196 B5125070 S5124244 BS1201 B5 125071 BS1202 B5 125138 B512 5136 B5125139 B5 125140 B512 5022 P547 8633 FC48 50 B54786 49 B5478 650 B512 5402 B5 12502 3 S5 124252 BS1228 KUNA SANTIAGO B5124841 B5125414 B5125072 PT S5 124254 J BARS B5125020 B5124 857 B5124860 V 5 124240 GS0945 N BS0117 B5124 752 BS1119 B5125021 S5124253 BS1145 KUNA SANTIAGO V 512 4246 GS0915 ADAPTABLE ADAPTABLE B5 142590 BS1203 B5125 404 B5125 403 B5 143857 B51429 41 B5142591 B5 143123 BS1654 B5142942 B5145 064 B5142 943 S51422 86 B51438 55 B5143624 B51438 56 S5 142291 S2291 BS1687 B5143477 B5143049 B5143 048 B51434 75 B514 3470 B5143472 B514 3473 S 5 1 4 3 5 8 BS1881 B5143 478 B5143476 P5644 119 B5142 973 B5 142976 B514 2972 B5 142592 B5142 983 B5142 981 B51429 82 B5143093 B5142975 B51429 77 B5143456 B5143 455 S5142281 B5143457 P5 3 8 5 5 8 6 P5 3 8 5 5 8 5 B5143050 B5143094 B514 3047 S5 143058 BS1580 B514345 8 P5644 122 FC4 19 8 B5 143124 B5142745 J 280A B5142980 BS176 6 B5143122 S5142 285 B5 142743 B5142 744 BØ BØ BØ BØ 7 5 0 CL P AØ AØ CØ CØ CØ BØ 7 50 CL P AØ 7 5 0 CL P C Ø C Ø BØ CØ BØ CØ CØ C Ø C Ø 1/ 0 J CN B Ø CØ 1/ 0 J CN CØ 1/ 0 J CN BØ BØ BØ CØ CØ BØ AØ BØ CØ 1/ 0 J CN BØ BØ BØ BØ CØ BØ 2 CL P 7 5 0 CL P 1/ 0 J CNLimited number of fault indicators
in 2018
– Additional automation after full saturation could lead to inaccuracies and slow the system down – Technology developed 20 years ago
capabilities
– Current operations (voltage regulation), fault location based on estimation methods
– E.g., overstressed circuit breakers – Increased complexity to operate and switch distribution system circuits due to variable and intermittent power flows
10
11
12
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,
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
13
0% 1% 2% 3% 4% 5% 6% 7% 0% 20% 40% 60% 80% 100% 7:00 8:45 10:30 12:15 14:00 15:45 17:30 19:15 21:00 Percentage of Circuits Generation Output Gen Output
Circuit Peak
As distributed energy resources are added to the grid, operating characteristics of the grid are changing, leading to increased complexity.
PV do not typically coincide
power for the benefit of the customer and the grid
powerflow and intermittent output from PV from an actual circuit, this appears as
magnitude and direction
14
2050
emissions to 40% below 1990 levels
sales from renewables
emissions to 80% below 1990 levels
emissions to 1990 levels
electricity sales from renewables
energy storage capacity by 2025
zero net energy
construction zero net energy
energy efficiency savings
2030 2020 Today
electrical vehicles
2025
10 years to cover 60% of SCE’s total distribution circuits (urban circuits)
Achieving our expansive energy and environmental policy goals will require taking foundational steps to evolve the grid.
today; expect over 300,000 by 2020
250 per month; in 2015, averaged 4,000-5,000 per month
incentives for DERs
15
Customers Are Adopting DER Customers Need Reliable Service
dependent on electricity
not accept a two-day power outage, even if they were paid as much as $1,000 for it
power outages cause “really significant problems” for their households
$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
16
17
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.
18
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 Improvement Image 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_restorat ion_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
constraints due to voltage, thermal, and protection limitations
reflect grid changes
to improve models to maximize integration capacity
10 20 30 40 50 60 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2010 2011 2012 2013 2014 2015 2016 MW Installed Number of Residential Installations Number of Installations MW Installed 19
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)
Image source: http://www.solarcity.com/company/distributed-energy-resources
20
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
21
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
22
Operations enhancement will provide more granular visibility to system conditions, and the ability for system operators to reconfigure the distribution grid and dispatch resources.
23
Communication systems must be secure, require larger bandwidth and low latency to support needed data transfer for timely, quality decisions.
Field Area Network Wide Area Network DER Provider Network Secure Gateway
24
Planning tools will enable forecasting, analysis, and sharing.
Load Growth Need Hosting Capacity Need Reliability & Operational Need
Identify Optimal Locations System Analysis External Communication Optimal Grid Solutions Grid Analytics Capacity Analysis Voltage 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
Streamlined Interconnection Present Information Online Load & DER Growth Develop Wires Solutions
Long Term Planning Tools Grid Analytics Applications
monitor, and manage grid resources in real time
fiber optic and field area networks to support timely data transport
reliability, and equipment obsolescence
25
Grid Reinforcement; Remove 4kV
1 1 2 3 4 4 3 2
26
SCE proposes a pilot to evaluate the potential deferral of eight load growth projects by using DERs in concert with a modern distribution system
customer and geographic diversity, and DER performance in concert with grid modernization
reliable, and effective manner
approximately $40 million capital request in this GRC
Test whether DERs can have a measurable impact on transformer life.
the life of a transformer
transformers
27
The capabilities realized through grid modernization will help enable opportunities for DERs including the opportunity to defer traditional infrastructure projects.
28
4a Grid Reinforcement 4b 4kV Systems 1a Distribution Automation 1b Substation Automation 2 Communications 3 IT T
29
$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 $1,000 2016 2017 2018 2019 2020 Nominal ($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
with appropriately- sized line sections for circuit switching, which will minimize de-energized sections during planned and unplanned outages
Definition Definition 4a 4a 1b 1b 3 2 4b 4b SCE’s Distribution Automation effort improves on the historical circuit automation program by installing automatic switches, sensors and circuit connections:
30
1 2 3
A fault occurs downstream of the mid-point RCS. Half the customers (Group A and B) will experience a momentary
Half the customers (Group C and D) will experience a sustained
The same fault occurs downstream of the mid-point
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.
Configura Configuratio ion Scenario n Scenario 4a 4a 3 2 4b 4b
Open Switch Closed Switch Fault
RCS Remote
Controlled Switch Circuit Breaker Substation Energized Line (Arrow Shows General Direction
Not Energized Line
RIS
Remote Intelligent Switch
No Outage Momentary Outage (< 5 mins) Outage
Grid Mo Mode dernization Di rnization Distr stributio bution A Automation ( tomation (after er sw switch ching) ing)
Historical Distribution Au Historical Distribution Automation (af tomation (after switching) er switching)
1b 1b
31
4a 4a 3 Necessity 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 4b
Substation A
Load: Load: Load:
Substation B
Load:
1a Distribution 1a Distribution Automation Automation 1b 1b
Masked Load Transfer Load
32
Scope & Deployment Scope & Deployment 4a 4a 3 2 4b 4b 1a Distribution 1a Distribution Automation Automation 1b 1b
– Allows for manageable load blocks for reconfiguration (~100A) – Minimizes customer impacts due to outages – Provides necessary data to inform current state power flow
and branches to optimize fault location (~10 per circuit)
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)
33
Cost Cost 4a 4a 3 2 4b 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:
Unit Cost) * Number of WCR Circuits
1a Distribution 1a Distribution Automation Automation 1b 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
34
Benefits Benefits 4a 4a 1a Distribution 1a Distribution Automation Automation 1b 1b 3 2 4b 4b
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:
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
capacity caused by masked gross load and supply resources (e.g., DG & energy storage).
grid services by managing constraints through circuit reconfigurations – which is the most effective & efficient means to manage distribution constraints.
35
1 Based on “Southern California Edison Customer Interruption Cost Analysis” performed by Nexant
4a 4a 1a 1a
1b Substat 1b Substation Automat
Common Substation Platform Substation Platform (CSP) (CSP)
3 2 4b 4b Definition 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.
36
4a 4a 3 2 4b 4b Necessity Necessity 1a 1a 1b Substation Automation & 1b Substation Automation & CSP 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:
SA-3 enablement:
control center.
37
4a 4a 3 2 4b 4b Scope & Deployment Scope & Deployment
396 substations will be upgraded over the next ten years based on locations where multiple circuits will be automated. Of these:
automation and will receive both SA-3 and CSP .
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 1a 1b Substation Automation & 1b Substation Automation & CSP CSP
38
4a 4a 3 2 4b 4b Benefits Benefits 1a 1a 1b Substation Automation & 1b Substation Automation & CSP CSP
telemetry necessary to ensure future DERs do not erode current level of reliability.
reliability from enhanced DA switching capabilities.
settings following circuit realignments.
39
4a 4a 1a 1a 3 4b 4b 1b 1b 2 Communication 2 Communication Definition Definition
FAN: Modern radio system allowing distribution automation switches and sensors to communicate with
substation. WAN: Expansion of existing fiber optic cable system between
centers and substations.
40
4a 4a 1a 1a 3 4b 4b 1b 1b 2 Communication 2 Communication Necessity and Benefits Necessity and Benefits
NetComm Utilization
(now 20 years old) currently has a typical command cycle time of two minutes.
impacted due to inadequate speed and capacity.
41
FAN:
latency of less than 100 milliseconds and an overall latency of less than 15 seconds. WAN
and CSPs, need to be supported with fiber optic communication between substations.
4a 4a 1a 1a 3 4b 4b 1b 1b 2 Communication 2 Communication Scope & Development Scope & Development FAN Deployment Plan
A failure-resistant “mesh” network
This “mesh” requirement mandates deployment by geographical area.
WAN Deployment Plan
42
These 531 miles of fiber will connect 42
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 T 3 IT T
MT / DRP EP EP 4a 4a 1a 1a 4b 4b 1b 1b 2
The Syst System Mode Modeling Tools (SMT) Tools (SMT) leverages power system modeling for engineering analysis of the distribution grid. Distribution R tribution Resource Pl source Plan Externa ternal Po Portal (DR rtal (DRPEP) EP) is an interactive web portal that publishes analyses results.
circuit duty, transients, protection coordination, harmonics, capacity optimization
access to information/data regarding circuit interconnection capacities.
section and node
upload DER data
What ? What ?
Current software tools used for analyzing capacity require significant manual efforts that rely upon conservative assumptions which limit precision.
for feasibility requests to connect DERs
conservative assumptions,
submittals increases time required for interconnection review
published in DERiM is updated
information can misinform customers’ interconnection decisions
Necessity Necessity
DER adoption is encouraged by improving SCE processes that calculate and publish system planning and interconnection data such as ICA
siting opportunities is improved through granular understanding
throughout the grid
tools to support data interrogation, analysis, and download
unhindered by conservative modeling assumptions and with minimal delay.
to perform power system analyses on SCE electrical system
Benefits Benefits
43
3 IT T 3 IT T
MT / DRP EP EP 4a 4a 1a 1a 4b 4b 1b 1b 2
44
System Modeling Tool Scope & Development Scope & Development DRP External Portal
3 IT T 3 IT T
MS 4a 4a 1a 1a 4b 4b 1b 1b 2
SCE’s Gri Grid Manage Manageme ment Syste System (GMS) (GMS) is an advanced software tool that will receive and analyze real- time information on customer energy usage, power flows,
status.
control centers and grid assets to facilitate operations in response to
infrastructure management applications that include a heightened level of intelligence and control necessary to effectively manage an increasingly complex distributed grid.
What ? What ?
With DERs being connected to the grid, operators have been given a fourth responsibility – optimize the benefits of DERs.
the operator about distribution circuitry and limited level of control an operator has over the circuit.
increases grid management inadequacies that will not allow:
including DERs
awareness
dynamic settings
management
Necessity Necessity
The GMS will provide safety and reliability benefits and support the realization of DER Potential
unplanned outages
management
situational awareness
and recommendations to system
to support public and worker safety and avoid equipment damage
leverages DERs
Benefits Benefits
45
3 IT T 3 IT T
MS 4a 4a 1a 1a 4b 4b 1b 1b 2 Scope and Development Scope and Development
Phase 1:
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:
introducing complex grid management functions to manage and optimize DERs to utilization and enhance grid reliability. This phase includes functions such as power flow
protection, micro-grid management, and a comprehensive training simulator to support organization readiness of the new grid management functions. Target completion in 2020.
46
3 4a Grid 4a Grid Reinfor Reinforcement ent 1a 1a 1b 1b 2 4b 4b
47
– Covers short term upgrades needed to solve distribution needs that arise due to increased demand
– Work types covered
– Additional drivers
breakers
– Cutovers and eliminations
48
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
connected to the distribution system while maintaining system safety and reliability
existing system conditions (system ratings and DER) and DER projection to 2020*
* Based on preliminary analysis of updated DER growth scenarios
3 4a Grid 4a Grid Reinfor Reinforcement ent 1a 1a 1b 1b 2 4b 4b
2015 GRC)
– Aging infrastructure – Operational flexibility constraints – Operation and maintenance constraints – Need for expansion and space constraints – Insufficient capacity – Forecasted reverse power flow
– Run to failure – Manual load curtailment – Rebuild existing substation – Partial cutovers
3 4a 4a 1a 1a 1b 1b 2 4b 4kV Systems 4b 4kV Systems
49
neighborhoods
– Approximately 26% of SCE’s customers are in disadvantaged communities – Approximately 44% of customers in disadvantaged communities are on 4kV circuits
– Thermal – Unbalance and ground protection
available 12 and 16kV facilities
– There is no ability to pick up load during planned or unplanned outages
kV due to higher losses at the lower voltage 3 4a 4a 1a 1a 1b 1b 2 4b 4kV Systems 4b 4kV Systems
50
Many 4 kV substations are in space constrained areas, limiting the possibility of expansion
3 4a 4a 1a 1a 1b 1b 2 4b 4kV Systems 4b 4kV Systems
51
52
customers utilize the grid in expanding ways
capabilities the current grid and utilities need to evolve and develop
transmission grid operations requires tight coordination between the DER operator, the utility, and the ISO to ensure reliability and confirm DER performance for compensation
53
SCE looks forward to additional opportunities to discuss and clarify
54