Rule 21 Working Group 2 - Gridworks...deployed SIs against expected configurations. Project...

Rule 21 Working Group 3

SIWG CALL ISSUES 27 AND 28

JANUARY 11, 2018

HTTPS://ZOOM.US/J/488565400

https://gridworks.org/initiatives/rule-21-working-group-3/

https://zoom.us/j/488565400

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Agenda

2:30-2:55 Regulatory updates, including PG&E presentation of smart inverter working paper

2:55-3:10 Review Issue 27-28 brief (Jan 4) from last call

3:10-3:25 Proposals from parties

3:25-3:55 Discussion of topics 1-8 from Jan 4 issue brief

3:55-4:00 Next steps


Smart Inverter Working GroupIssues 27 & 28

PG&E Presentation: Smart Inverter EPIC Demonstrations and Joint IOU SI White Paper

January 11th, 2019

Grid Integration & InnovationDistributed Energy Resource (DER) Demonstration Projects

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PG&E Smart Inverter EPIC Demos and Joint IOU SI White Paper

Agenda:

1. EPIC 2.03A SI Demo Background

2. SI Demo Objectives

3. Technical Results, Learnings, and Challenges:

A. Location 2 Field Testing

B. Lab Testing

C. SI Modeling

4. Joint IOU SI White Paper Framework


Smart Inverters: A Key Technology Enabling CA DER Policy

• Smart Inverters can make autonomous decisions that can help maintain grid reliability and power quality

• Currently, Smart Inverter penetration in CA is low, but policies and investments need to be adopted in anticipation of rapid growth in SIs

• By 2021, approximately half of all behind-the-meter PV installations in CA will have Smart Inverters

• By 2028, nearly all BTM PV in CA will have Smart Inverters

Why did PG&E undertake this EPIC project?

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5,000

10,000

15,000

20,000

2007 2010 2013 2016 2019 2022 2025 2028

Inst

alle

d C

apac

ity

(MW

-AC

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CA Statewide BTM PV Capacity and SI Penetration

SI-Enabled PV

50%

50%

2022

100%

2028

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EPIC 2.03A Smart Inverter Demo Key Objectives

Component

• Field-test SI impact to voltage on secondary and primary

• Measure customer curtailment from Volt VAR/Volt Watt SI Grid Impacts

• Test capabilities of two types of SI aggregation platforms: 1) Vendor-specific platform 2) Vendor-agnostic platform

SI to Utility Communications

• Evaluate SI ability to execute Phase 1 & Phase 3 functions

• Test SI performance in edge cases (harsh grid conditions)SI Lab Testing

• Evaluate impact of PV and PV + storage with/without SIs on several Dx feeders

• Perform economic analysis of SIs vs. standard Dx upgrades

SI Modeling Study

Key Objectives

LOCATION 1 INTERIM REPORT FINDINGS*

*Link to PG&E EPIC 2.03A Smart Inverter Interim Report: https://tinyurl.com/y8p6j3a4

https://tinyurl.com/y8p6j3a4


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EPIC 2.03A Location 1 and Location 2 Field Tests

15 assets, 62.5 kW capacity 14 assets, 4.5 MW capacity

❖ Feeder with high penetration of commercial scale PV

❖ Demo field assets account for ~35% of peak feeder load

❖ Known voltage issues due to PV❖ SI assets commissioned in early

2018; tested through 9/18

❖ Mixed use feeders with moderate PV penetration

❖ Demo field assets account for


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Location 2 Example Field Test Site - SVD

1MW SVD Field Site – 41 Inverters

Existing SI cluster controller

New comm. gateway

Existing satellite modem

Existing Inverter updated with new firmware/comm. gateway


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Location 2 Field Demo Results


Example Location 2 Active/Reactive Power Measurements

• Key Takeaways: Properly configured SIs successfully executed the Volt-Watt and Volt-VAR curve settings within tolerances, with a negligible percent of data points falling outside the tolerances

• Voltage on the feeder was elevated due to high PV penetration

• A total of 5 different VV/VW curves were tested

SI P and Q Measurements with Active Volt-Watt and Volt-VAR with Curve Set 1

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Voltage Violations by Volt-VAR/Volt-Watt curves across PV sites

Key Takeaways:• Enabling SI VV/VW curves

reduced % of secondary highvoltage violations on all sites

• The largest site (Site 2) experienced the fewest violations with VV/VW curves enabled

• Curves with more reactive power output were more effective in reducing high voltage violations

No Volt-VAR/Volt-Watt

Site 1, 984 kW

Site 2, 620 kW

Site 3, 372 kW

Site 4, 264 kW

Site 5, 264 kW

Site 6, 264 kW

Site 9, 222 kW

Site 10, 210 kW

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Primary Voltage by Volt-VAR/Volt-Watt curves across PV sites

Key Takeaway:• At the 35% feeder peak

load PV penetrations tested, SI Volt-Watt/Volt-VAR showed no clear effect on elevated average primary feeder voltages.

• While the SI Volt-VAR and Volt-Watt functions are an important component of voltage regulation, the project has highlighted that SIs should be viewed as one component of a larger strategy referred to as integrated voltage regulation.

No Volt-VAR/Volt-Watt

VV/VW Curve 1

VV/VW Curve 2

VV/VW Curve 3

VV/VW Curve 4

Average Primary Feeder Voltage by Volt-VAR/Volt-Watt Curve Set

Unity Voltage ->

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PV Production Curtailment Due to SI Volt-VAR/Volt-Watt

Key Takeaways: • Customer generation curtailment due to

activation of VV/VW curves on a feeder with persistent voltage violations was minimal

• Testing on average resulted in 0.48% curtailment at the SIs as compared to a baseline SI running no VV/VW curves

• Maximum curtailment observed across the Stage 3 sites and curve periods was 1.01% (Stage 2 = 1.2%)

• Amount of curtailment was not correlated with site size

Curve B1 Curve C1 Curve D1 Curve E1

Site 1 984 0.45 0.6 0.46 0.57

Site 2 620 0.6 0.16 0.49 0.27

Site 3 372 0.49 0.71 0.46 0.38

Site 4 264 0.45 0.5 0.28 0.32

Site 5 264 1.01 0.71 0.49 0.38

Site 6 264 0.45 0.61 0.25 0.09

Site 7 264 0.33 0.47 0.17 0.42

Site 8 240 0.67 0.61 0.7 0.36

Site 9 222 0.37 0.9 0.38 0.7

Site 10 210 0.61 0.68 0.5 0.26

Site 11 210 0.28 0.18 0.35 0.12

Site 12 132 0.45 0.57 0.56 0.73

Site 13 102 0.66 0.6 0.53 0.71

Test SitePV Site Size

(kW)

% Production Curtailment by Curve Set

Avg. Curtailment (%): 0.48

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Location 2: Key Learnings on Aggregation Platform/Communications

Initial agg. platform firmware led to inconsistent application of SI settings and data transmission to PG&E.

Communications/power outages at the test sites caused the agg. solution to shut down or lock up.

Project Observations:

In this project, satellite communications proved to be more reliable than cellular.

Round-trip latency was lower for cellular vs. satellite.

Key Takeaways and Recommendations:• There is not yet an out-of-the-box vendor-agnostic SI aggregation

solution that allows seamless interoperability between DERs, aggregators, and utilities.

• Aggregation platforms will need to be tailored and customized to specific DER communication infrastructure and DER use cases.

• Tools to identify and mitigate system failure (to increase end-to-end system reliability) need to be developed to have a situational view of SI assets and communication pathways.

• Degraded communication link quality testing should be included as part of any engineering, installation, and commissioning process (EIC) for SI-enabled DER aggregations.

• Cybersecurity standards are critical and need to be adopted by the industry and integrated into relevant communication standards for SI interconnection.


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SI Lab Testing


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Results of SI Lab Testing by PG&E

One vendor’s product was defective out of the box and could not be lab-tested until a replacement was received.

A second vendor’s products did not function when the Rule 21 settings were applied, resulting in 3 SI failures.

A third vendor’s product shut down at 107% p.u. voltage although it was within the expected operating range.

Key Takeaways and Recommendations:

• SI vendor preparedness regarding Rule 21 Phase 1 Autonomous Function implementation needs improvement.

• Standardization of SI feature names and functions across mfrs. would significantly facilitate verification of configuration.

• Improved SI manufacturer product documentation is needed.

• Further progress needs to be made on capabilities to automate verification of deployed SIs against expected configurations.

Project Observations:

All three vendors’ products tripped/disconnected within 0.16s (9 cycles) upon opening of a line recloser, within IEEE 1547-2018 requirements.

While lab testing revealed issues with new SIs shipped in summer of 2018, previously-commissioned SIs worked well in field testing.


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EPRI SI Modeling


EPRI SI Modeling Study Background

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Key scope elements for the modeling study included:

Detailed study of 6 representative PG&E distribution feeders in Open DSS1

Modeling of PG&E primary and secondary circuit topology & characteristics• Evaluation of engineering standards for secondary voltage rise

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Inclusion of PV and PV + Storage (20% of all BTM interconnections now include storage)

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The study focused on comparing scenarios without smart inverters to scenarios with smart inverters, focusing on Volt-VAR/Volt-Watt

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Economic analysis of SI functions for grid support vs. traditional investment 5


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EPRI Residential SI Modeling – Voltage Violations from PVMaximum Transformer Count with Secondary Overvoltages (only residential PV systems modeled)

Key Takeaways: • Modeled SI functions reduced, but did not

entirely suppress overvoltage conditions arising from high PV penetration.

• The reduction was comparable, and sometimes superior to the performance obtained with conventional upgrades such as new secondary (service) transformers.

• The SI modeling study was not able to demonstrate a scenario in which autonomous SIs mitigated a conventional upgrade on the primary, medium voltage system.

• Economic impact of SIs for ratepayers was very small, but positive compared to conventional secondary system upgrades.

• All three VV/VW curves were on average more effective than conventional upgrades; curves with more reactive power were more effective.

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Conventional measures

Smart Inverter functions

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Smart Inverter functions

X Axis: Residential PV penetration vs. peak load: PV 1: 25% PV 2: 50% PV 3: 75% PV 4: 100%


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EPIC 2.03A Summary of Key FindingsComponent

• Significant potential for voltage support from SIs to help mitigate local secondary voltage challenges caused by high PV penetration; no clear effect seen on the primary

• Customer curtailment from Volt-VAR/Volt-Watt was minimal (.4% avg., 1.2% max)SI Grid Impacts

• SI aggregation platforms will need to be tailored and customized to specific DER communication infrastructure and DER use cases; no out-of-the-box solution exists

• Rigorous pre-deployment testing of SI aggregation platform software & firmware needed to ensure reliable behavior under degraded communication/grid power conditions

SI to Utility Communications

• Testing was heavily hindered by poor product readiness and SI equipment failures

• Unified standards, comprehensive testing and certification, and improved manufacturer product documentation and standardization of SI feature names and user interfaces needed

SI Lab Testing

• Autonomous SI functions yielded a small but positive economic impact for ratepayers compared to conventional upgrades used to mitigate voltage issues from high PV penetration

• PG&E can eliminate its secondary voltage rise study process for BTM PV interconnection when Volt-VAR and Volt-Watt are activated, which will benefit customers and developers

SI Modeling Study

Key Findings


California Joint IOU Smart Inverter White Paper

• Link to the Smart Inverter White Paper• Link to the Smart Inverter White Paper

Appendix• Link to EPIC 2.03A Smart Inverter

Interim Report• EPIC 2.03A Final Report (Findings

discussed above) available in Feb.• EPIC 2.02 (DERMS) Final Report

available later this month

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https://www.pge.com/pge_global/common/pdfs/about-pge/environment/what-we-are-doing/electric-program-investment-charge/Joint-IOU-SI-White-Paper.pdfhttps://www.pge.com/pge_global/common/pdfs/about-pge/environment/what-we-are-doing/electric-program-investment-charge/Joint-IOU-SI-White-Paper-Appendix.pdfhttps://www.pge.com/pge_global/common/pdfs/about-pge/environment/what-we-are-doing/electric-program-investment-charge/PGE-EPIC-Project-2.03a.pdf?WT.mc_id=Vanity_epicinterimreport-SmartInverters


SI White Paper – Overview of CA Joint IOU SI Learnings

Key Takeaway: Read the White Paper to learn more about CA Joint IOU SI Demonstrations

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SI White Paper: Factors to enable DERs for Grid Services

Issues already being addressed in IDER that Rule 21 should not duplicate:• Can the grid need be met cost-effectively by DERs relative to traditional distribution upgrades?• Are the deployed DERs incremental to what has already been forecasted by Distribution Planning, and is there any risk of double compensation?• Are the DERs potentially creating additional issues/solving issues they created (e.g. reverse flow or elevated voltage from high PV penetration)?• Can non SI-enabled DERs (Demand Response, Energy Efficiency, Permanent Load Shift, Electric Vehicles) meet the need?

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Key SI White Paper Messages

Location and volume of Smart Inverter-enabled DERs on the distribution grid is important

Timing of Smart Inverter-enabled DER response should align with distribution grid need

Availability and assurance of Smart Inverter-enabled DERs to provide grid response is needed

Coordination between the utility and DERs or DER aggregators is important

Grid modernization initiatives are necessary for Smart Inverter-enabled DERs to provide distribution grid services beyond autonomous Smart Inverter functions

Unified standards, comprehensive testing and certification, and training for DER installers are needed to ensure consistent Smart Inverter operation, communication and cybersecurity

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Value of EPIC to PG&E & CA State Policy Objectives


Thank You

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Issues 27 and 28

Issue 27. What should be the operational requirements of smart inverters? What rules and procedures should the Commission adopt for adjusting smart inverter functions via communication controls?

Issue 28. How should the Commission coordinate with the Integrated Distributed Energy Resource proceeding to ensure operational requirements are aligned with any relevant valuation mechanisms?

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Phase 1

Phase 1 Autonomous Functions (approved April 2015)

• Anti-Islanding

• Voltage Ride-Through

• Frequency Ride-Through

• Volt/VAR Control

• Default and Emergency Ramp Rates

• Fixed Power Factor

• “Soft-Start” Methods

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Phase 2

Phase 2 Communications (approved April 2017)

• Three Pathways:• IOU – DER

• IOU – DERMS

• IOU – Retail Aggregator

• Default Protocol: IEEE 2030.5 (aka SEP 2.0)

• Capability only, not yet functional communications

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Phase 3

Phase 3 Advanced Functions

1. Monitor Key DER Data

2. DER Cease to Energize/Return to Service Request

3. Limit Maximum Real Power Mode

4. Set Real Power Mode

5. Frequency-Watt Mode

6. Volt-Watt Mode

7. Dynamic Reactive Current Support Mode

8. Scheduling Power Values and Modes

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Issue 27-28 Brief (Jan 4)

1. Define a clear line between “non-valuation” and “valuation” related operational requirements:

• Non-valuation side: operational requirements for reliability services, resiliency, grid support, mitigation of impact of DERs, avoided wire upgrades.

• Valuation side: operational requirements for grid services in the context of a market or communication protocol to capture a certain value stream. Needs narrowing, defining, and clarifying. Return to this after IDER gets further along with sourcing mechanisms.


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2. Define use cases for non-default values:

• Use case #1: Adjust VOLT-VAR set-point to provide voltage support (with payment to customer?).

• Use case #2: Limit active power to a threshold in abnormal operating conditions. How and when? (Real-time for a specific circuit, and not a dynamic operational flexibility limit for ICA.)

• Other use cases? What does the grid need?


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3. Define circuit-level blanket activation criteria:

• Under what conditions could (should) we use blanket activation of certain functions, rather than individual activation? (For example, circuit-level penetration threshold as a function of load or hosting capacity.)

• What is the range of non-default settings the utility can set?

• What are some alarms or similar measures to mitigate leaving functions activated for longer than intended?

• Proposed: communication activation would be on a going forward basis at interconnection. Retroactive activation would only be implemented by mutual agreement.


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4. Which functions should be allowed by mutual agreement between the distribution provider and customer? Suggested:

• Telemetry

• Mitigating issues identified at time of interconnection

• Operation during abnormal conditions (e.g., a customer could choose to be controlled during abnormal conditions, rather than manually disconnected as may happen today)


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5. Should our proposal be based solely on capabilities available today, or also include those capabilities to come along with IEEE 1547?

6. Should our proposal address implementation of Phase 2, and possible extensions to address the communication issues and testing challenges currently being faced with (by) aggregators?

7. Should our proposal provide limits (“rails”) on the adjustability of a function/parameter to ensure a customer isn’t overly impacted (e.g. maximum slope of volt-watt, maximum curtailment, maximum “cease to energize” time)?


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8. How does Gabe’s framework, presented and extended below per the discussion, help us define operational requirements?

• Suggestion: let’s focus first on operational requirements for (a) and (b). What are these requirements?

• Comment from Roger: we can already do (b) and (c).

• Comment from Gabe: for (e), the IDER proceeding will not be able to identify functions as well as this extended WG3-SIWG technical group could, so keep (e) as placeholder for future joint SIWG-IDER work.


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Issue 27-28 Brief (Jan 4)(a) Alternate settings that avoid upgrades

(b) Emergency or temporary settings

(c) Brand-new default settings

(d) Transactional grid services with some type of compensation

(e) Specific to IDER tariff (sourcing mechanisms)

Opportunity for finding common ground in WG3 ✓ ✓

Open-ended, operational requirements not so clear ✓

Grey area between capabilities and tariffs ✓

Leave to (support) IDER at appropriate time ✓

Safety and reliability related✓ ✓ ✓

Valuation-related (possible)✓ ✓ ✓

Reiterates vision of DER Action Plan (Section 2.F) ✓ ✓

Use case #1: adjust VOLT-VAR set-point ✓ ✓

Use case #2: limit active power output ✓ ✓

Use case #3: ???


Rule 21 Working Group ThreeIssue 27 – Smart Inverters

Brad HeavnerCALSSA Policy DirectorJanuary 11, 2019

Goals of Issue 27 Proposal

Issue 27: What should be the operational requirements of smart inverters? What rules and procedures should the Commission adopt for adjusting smart inverter functions via communication controls?

Goals:

• Identify priority use cases

• Define procedures and rules for services anticipated from IDER tariffs

• Set target deployment of DERMS

Voltage Functions

• DERs can provide voltage support as a routine management tool or in response to abnormal conditions.

• Proposals for tariffs to facilitate this activity are due in the IDER proceeding (R.14-10-003) on February 15.

• Smart inverters have three voltage functions. Changing from the default settings can provide grid support.

• Volt/Var

• Volt/Watt

• Fixed Power Factor (in place of Volt/Var)

Voltage Support Use Cases

• Change settings of voltage functions in response to feeder reconfiguration

• Procedure: Customer agrees to tariff (available in all locations) as part of interconnection application. When exercised, utility sends a command to facility or aggregator.

• Rule: Range of adjustability and frequency of use to be determined in IDER tariff.

• Schedule changes to settings of voltage functions to address seasonal differences

• Procedure: Utility determines locations where this is valuable. Customer agrees to tariff as part of interconnection application. Settings included in interconnection agreement or tariff agreement.

• Rule: Customer obligation to maintain schedule.

• Ongoing adjustments to settings of voltage functions in place of other voltage regulators

• Procedure: Utility offers agreement during interconnection review. When exercised, utility sends command to facility or aggregator.

• Rule: Aggregators use functionality as currently defined in Rule 21. Terms contained in IDER tariff.

Interconnection Use Cases

• Schedule changes to Limit Maximum Active Power (Function 3) in response to seasonal or hourly hosting capacity constraints• Procedure: Customer proposes operational profile in interconnection

application. Utility compares profile to hosting capacity in Screen M. Schedule contained in interconnection agreement.

• Rule: Customer obligation to maintain the schedule.

• Curtailment using DER Disconnect and Reconnect (Function 2) in response to abnormal grid operations to address operational flexibility constraints• Procedure: Range of adjustability proposed by customer in

interconnection application according to ICA-OF. Utility compares to hosting capacity in Screen M. When exercised, utility sends a command to facility or aggregator. Range of adjustability contained in interconnection agreement.

• Rule: Customer obligation to perform on command.

Other Use Cases

• System restoration – When service is restored to a circuit after a grid outage, communication with smart inverters can stagger the timing of DERs coming back online to avoid voltage spikes

• Procedure: Utility sends a command to facility or aggregator prior to system restoration, or alternative start time is agreed to ahead of time.

• Rule: Customer obligation to perform, subject to coordination with IDER tariff.

• Storage dispatch as a capacity resource

• Procedure: Customer agrees to resource adequacy or demand response obligation. When exercised, utility sends command to facility or aggregator.

• Rule: Customer obligation to perform contained in tariff or solicitation.

DERMS Are Part of This Issue

• In order to utilize Phase 3 functions, utilities need to build communications systems on their end.

• Customers are required to deploy capabilities. Utilities should also be required to deploy capabilities.

• Utilities have built DERMS for pilot projects ordered by the CPUC.

• In Issue F, Working Group 4 will discuss the relationship of DERMS and the Operational Flexibility ICA constraint. That is only one use case.

• CALSSA requests that utility DERMS managers give an update on the Jan 31 SIWG call.

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Next Steps


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