Essential Reliability Services - NERC Highlights and...annual frequency response report for all interconnections. • The FRAA establishes the Interconnection Frequency Response Obligation

Essential Reliability ServicesTransition to ERSWG and DERTF

Brain Evans-Mongeon, ERSWG Co-ChairPlanning and Operating Committee , ERSWG, & DERTF MeetingsMarch 7-10, 2016

RELIABILITY | ACCOUNTABILITY2

Introduction

Update on 2015 deliverables Transition to a Working Group

Approve Scope and Work Plan


• December 2015 – NERC Board approved:

Framework Report Abstract Document ERS Videos

ERSTF Completion

http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20Report%20-%20Final.pdf

http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERS%20Abstract%20Report%20Final.pdf

https://vimeopro.com/nerclearning/erstf-1


Endorsed Assignments from ERS Framework

ERSTF Completion

Ref Number Title ERS Recommendation

Ongoing Responsibility

1 Synch Inertia at Interconnection Level Measure

RS & FWG2 Initial Frequency Deviation Measure

3 Synch Inertia at BA Level Measure

4 Freq Response at Interconnection Level Measure

5 Real Time Inertial Model Industry Practice BA

6 Net Demand Ramping Variability Measure RAS

7 Reactive Capability on the System Measure PAS & SAMS

9 Overall System Reactive Performance Industry Practice EAS

10 System Strength Industry Practice PC


NERC Board Endorsed Future Work

• ERSTF ERSWG • Define and develop ‘Sufficiency Guidelines’ for each measure• Focus on Distributed Energy Resources, hence DERTF formed as

an additional subgroup• Monitor and Track ERS Measures assigned to PC and OC

Subcommittees, coordinate as needed


2016 and 2017 Deliverables

2016 Deliverables:• Whitepaper on methodology for ERS

Measures Sufficiency Guidelines• Final Report on DERTF

2017 Deliverable:• Final Report on ERS Measure Sufficiency

Guidelines


Logistics

• ERSWG meetings will follow NERC Standing Committee meetings Bi-weekly leadership calls to continue

• Other WG meetings and calls will be determined on as needed basis


Conclusion

• The ERS co-chairs request the OC and PC to approve the Scope and Work Plan (as presented in the background materials) for: Essential Reliability Services Working Group

– Distributed Energy Resources Task Force


IEEE 1547 Revision Update

Ryan D. Quint, Ph.D., P.E., Senior Engineer, System AnalysisNERC Planning Committee MeetingMarch 2016


• IEEE 1547: Standard for Interconnecting Distributed Resources with Electric Power Systems Scope: Establishes criteria and requirements for interconnection of

distributed resources (DR) with electric power systems (EPS) Purpose: Provides uniform standard for interconnection of DR with EPS.

Provides requirements relevant to the performance, operation, testing, safety considerations, and maintenance of the interconnection.

• NERC believes that Frequency Response and Voltage Support are Essential Reliability Services (ERS) to the Bulk Power System (BPS)

• As DR penetration increases and DR becomes a key component to BPS performance, it is critical that DR operation and control strategies align with the needs of the BPS for long-term reliability.

• We see an opportunity to get out in front of the problem before it becomes a reliability risk.

Background


• The standard is an equipment standard; however, ensuring the capability is available and in-service is a reliability issue of the BPS

• NERC is engaging primarily in revisions to Clause 4.2: “Response to Area EPS abnormal conditions” Voltage Ride-Through Dynamic Voltage Support Frequency Ride-Through Frequency Response Capabilitieso Frequency-Droop Characteristico Deadband Settings

Engagement


• Category I: Based on essential bulk electric system (BES) stability/reliability needs and reasonably attainable by all DER technologies that are in common usage today

• Category II: Covers all BES stability/reliability needs and coordinated with existing reliability standards* to avoid tripping for a wider range of faults**

• Category III: Based on both BES stability/reliability and distribution system reliability/power quality needs and coordinated with existing interconnection requirements for very high penetration DER regions***

*e.g., NERC PRC-024-02**a) 1LG stuck breaker transmission faults; b) normal and delayed clearing faults at lower-level transmission and subtransmission (fault durations can be longer primarily due zone relaying)*e.g., CA Rule 21

Performance Categories


Voltage Ride-ThroughCategory II

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1.30

0.01 0.1 1 10 100 1000

Volta

ge (p

.u.)

Time (s)

shall trip1.20 p.u.13 s

1.10 p.u.

0.00 p.u.

0.88 p.u.

0.16 s

0.00 p.u.

0.50 p.u.

21 s

Continuous Operation

Mandatory Operation

Permissive Operation

shall trip

0.32 s 2 s

2 s

21 s

1

2

1

may ride-through or may trip

may ride-throughor may trip


0.88 p.u.

NERCPRC-024-2

Category II(based on NERC PRC-024-2 and considering FIDVR issues to a certain extent)

0.45 p.u.

0.65 p.u.

Permissive Operation

0.16 s

voluntaryride-through

0.16 s

Legend

range of adustability

default value

shall trip zones

may ride-through ormay trip zones

shall ride-through zonesand operating regionsdescribing performance

Based on PRC-024-2 and delayed voltage recovery


Voltage Ride-ThroughCategory III

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1.30

0.01 0.1 1 10 100 1000

Volta

ge (p

.u.)

Time (s)

Momentary Cessation

shall trip1.20 p.u.0.16 s

13 s1.10 p.u.

0.00 p.u.

0.88 p.u.

21 s

0.00 p.u.

0.50 p.u.

Continuous Operation

Mandatory Operation

shall trip

10 s

2 s

2

1 s1

2


Momentary Cessation

Category III(based on CA Rule 21 and Hawaii)

20 s21 s

50 s1

may

ride

-thr

ough

or m

ay tr

ip

12 s

0.88 p.u.

may

rid

e-th

roug

hor

may

trip Legend


default value

shall trip zones



Based on high penetration regions (CA Rule 21, HI)


• “DER shall have capability of [DVS] during Low-Voltage… and High-Voltage Ride-Through…”

• Essentially change DER real and reactive current as best possible to control DER Point of Connection.

• Open-loop Response Time: 50-100 ms• Setting Time: 2-2.5x of Response Time

Dynamic Voltage Support

Requirements of a Dynamic Voltage Support operation – Categories I, II, and III

Category Operation for Low-Voltage Ride-Through

Operation for High-Voltage Ride-Through

Category I optional optionalCategory II Mandatoryoptional mandatoryoptionalCategory III mandatory mandatory


Frequency Ride-ThroughAll Categories

Settings are well aligned with BPS needs.

56.0

56.5

57.0

57.5

58.0

58.5

59.0

59.5

60.0

60.5

61.0

61.5

62.0

62.5

63.0

0.01 0.1 1 10 100 1000

Freq

uenc

y (H

z)

Time (s)

Continuous Operation(V/f ≤ 1.1)

Mandatory Operation

Mandatory Operation

shall trip

shall trip

66.0 Hz 66.0 Hz

1 000 s0.16 s

180 s

62.0 Hz

50.0 Hz

0.16 s 1 000 s

50.0 Hz

57.0 Hz

1 000 s180 s1

2

2

161.0 Hz 1 000 s

59.0 HzLegend


default value

shall trip zones






Category I, II, and III(harmonized)

299 s

299 s

60.6 Hz

may ride-through or may trip


• Two concepts being proposed: Changing droop line characteristic based on output level; OR Constant linear droop line (conventional droop successfully used for many,

many years)

• Response Time: 100 ms; Setting Time: 2-2.5x of Response Time

Frequency-Droop Requirement

Formula for frequency-droop (frequency/power) operationOperation for Low-Frequency Ride-Through Operation for High-Frequency Ride-Through

𝑝𝑝

= min𝑓𝑓<60−dbUF

𝑥𝑥pre � 𝑝𝑝avl +60 − dbUF − 𝑓𝑓

60 � kUF,𝑝𝑝avl

OR

𝑝𝑝 = min𝑓𝑓<60−dbUF

𝑝𝑝pre +60 − dbUF − 𝑓𝑓

60 � kUF,𝑝𝑝avl

𝑝𝑝

= max𝑓𝑓>60+db𝑂𝑂𝑂𝑂

�𝑥𝑥𝑝𝑝𝑝𝑝𝑝𝑝 � 𝑝𝑝avl


• Two concepts being proposed:

Frequency-Droop Requirement

EI UFLS


Deadband Settings

• Working with IEEE 1547 team to better understand frequency control fundamentals and need for tight or no deadband

• Confusion across industry on this topic: distribution, vendor, and BPS industry level.

Parameters of frequency-droop (frequency/power) operation –Category I, Category II, and Category III

Parameter Ranges of adjustability(not a design criteria)

Default settings1

Category I Category II Category III

Category I Category II Category III

dbOF, dbUF[Hz]

0.017 –1.0

0.017 – 1.0 0.017 – 1.0 0.036 0.036 0.036

kOF, kUF[p.u.]

0.03 –0.05

0.03 – 0.05 0.02 – 0.05 0.05 0.05 0.051 Adjustments shall be permitted in coordination with the Area EPS operator.


Alignment of Efforts to Maintain Adequate Frequency ResponseNERC Planning and Operating Committee MeetingSeptember 15-16, 2015


• FERC Notice of Inquiry• Monitoring of ERS Measures Long-Term Reliability Assessment State of Reliability Report

• NERC-ERAG Scenario Assessment on Frequency Response in Eastern Interconnection

• ERSWG Development of Sufficiency Guidelines

Upcoming Advancements


Many Moving Parts

Frequency Response

Regulatory Actions

FRAA

Alert

RS/OC Guideline

BAL-003

SOR Report

LTRA

ERSWG

Providing desired effect

Providing some desired effect

Currently inconclusive Potentially negative effectNot providing desired effect

**Dial positions are for discussion purposes**


Many Moving Parts

Frequency Response

Regulatory Actions

Alert

RS/OC Guideline

BAL-003

SOR Report

LTRA

ERSWG

FRAA

Frequency Response Annual Analysis (FRAA)

Complete and Ongoing• NERC System Analysis develops an

annual frequency response report for all interconnections.

• The FRAA establishes the Interconnection Frequency Response Obligation (IFRO) and Balancing Authority Frequency Response Obligations (BA FRO).

• The FRAA was approved by the OC in September 2015

• 2015 FRAA is complete• 2016 FRAA is underway and ahead

of schedule.


Many Moving Parts

Frequency Response

Regulatory Actions

Alert

RS/OC Guideline

BAL-003

SOR Report

LTRA

ERSWG

FRAARegulatory Actions

Work in Progress• Industry stakeholder group

established to work with RS/OC/PC/ERSWG leads to develop comments for FERC NOI, advocacy for changes to SGIA/LGIA


Many Moving Parts

Frequency Response

Regulatory ActionsRS/OC Guideline

BAL-003

SOR Report

LTRA

ERSWG

FRAAAlert

Complete• RS and FWG developed a NERC

Advisory Alert on governor response.

• The advisory alert was published in January 2015 and addressed governor response and control coordination for synchronous generation.

• Webinars and industry outreach conducted

• Improvements should be measurable for each generator as well as the interconnection as a whole.

Alert


Many Moving Parts

Frequency Response


SOR Report

LTRA

ERSWG

FRAABAL-003

Work in Progress• NERC Reliability Standard BAL-003

defines an Interconnection Frequency Response Obligation (IFRO) and subsequent Balancing Authority obligations to preserve reliability and ensure the frequency nadir for the largest credible event stays above UFLS.

• The BA Submittal Site (BASS) has been set up for BAs to submit their data

• Webinars were conducted for registrants – recordings available

• Refinement to BAL-003 may be needed in the future.

Alert

BAL-003


Many Moving Parts

Frequency Response


LTRA

ERSWG

FRAA

State of Reliability Report (SOR)

Inconclusive• New measures to be included and

considered for the 2016 report.• 2016 report is due in May 2016.• The report addresses ERS and

other ALR Metrics and the FRM for each event (ALR 1-12 events)

• Currently has not found supporting data that firmly identifies a decline in frequency response.

• PAS will continue to analyze and support as necessary.

Alert

SOR Report

BAL-003


Many Moving Parts

Frequency Response


ERSWG

FRAA

Long-Term Reliability Assessment (LTRA)

Work in Progress• Key findings from past

assessments indicated a trend of more asynchronous resources and retirements of conventional generation, potential decreasing the overall inertia and frequency response capability of the BPS.

• In 2016, the LTRA includes an evaluation of ERS measures.

• The 2016 LTRA will be published in December.

• Special Assessment to be conducted on frequency response and the changing resource mix in Eastern Interconnection.

Alert

SOR Report

BAL-003LTRA


Many Moving Parts

Frequency Response


FRAA

Essential Reliability Services WG

Work in Progress• The ERSWG has four measures

relative to frequency for BA’s and interconnections.

• These measures also include revised ALR 1-12 metric (now metric M4).

• The WG will monitor activities of the working groups related to ERS measures

• The ERSWG will develop the initial strategy on quantifying the sufficiency guidelines for the ERS measures.

• Whitepaper to be competed by December 2016.

Alert

SOR Report

BAL-003LTRA

ERSWG


Many Moving Parts

Frequency Response

Regulatory Actions

FRAA

RS/OC Guideline

Phase I Completed• The RS and OC developed a

guideline for generator owners on governor response and DCS control strategies for thermal plants.

• The guideline includes industry recommended governor deadband and droop settings that will potentially enable resources to provide better frequency response to the BPS

• The OC approved the guideline in December 2015

• Being revised to add asynchronous resources (per Recommendation 1 of 2012 Frequency response Initiative report)

Alert

SOR Report

BAL-003LTRA

ERSWG

RS/OC Guideline


FERC NOI

The NOI seeks input on whether and what action is needed, including whether to: • Amend the pro forma Large Generator and Small Generator interconnection

agreements to require that each generating unit/facility connected to the BPS shall operate with the governor in service and responsive to frequency when the unit is online and released for dispatch (unless agreed upon with the BA)

• the performance of existing resources and whether to impose primary frequency response requirements on existing resources (in Reliability Standards, tariffs, or other formats); and

• requirements related to procuring and compensating primary frequency response.


Frequency Response Requirements:Different Approaches, Different Considerations

Not Required in Interconnection Agreement Required for All Generators

Relies on third-party/market mechanisms to meet requirements

- Requirement would apply to BAs; norequirement for GOs to have capability

- No measurable performance for GOs; only Interconnection and BA FRMs

- No requirements on deadbands – GOs can set however they like

- Wider frequency variability – status quo- No requirements on droop – GOs can set

however they like- Tendency to depend on “select few”

resources to meet BA FRO – what if offline?

- May drive stability risks for unbalanced response – heavy transfers on interties

- BA approach is unique to North America

Interconnection Requirement/Rule/Reliability Standard for frequency responsive resources

- Requirement would apply to all applicable GOs – “fair and equitable” capability

- Measurable performance for GOs- Requirement for reasonable deadbands in

support of frequency stability- Projected (seen in ERCOT) tighter control- Requirement for reasonable droop

controls in support of frequency stability- Wholesome reliance on all resources –

units always online- Operator flexibility- Uniform response alleviates intertie

pickups- Similar to most modern systems’ Grid

Codes


Developing the ERO Message

• Primary Frequency response (as part of overall frequency support) is an Essential Reliability Service (ERS).

• Essential for interconnection stability, prevention of equipment damage, coordination of droop response, and system restoration (cranking path).

• The ERSTF final report recommended that ALL resources have the capability to provide frequency response.


Developing the ERO Message

• FERC has enabled the sale of primary frequency response service at market-based rates

• Provisions for market-based sale of primary frequency response provides a mechanism for entities to be compensated when reducing generation output for frequency response reasons; however, there are no requirements that ensure that resources have the capability to provide frequency response.

• With a rapidly changing resource mix, ensuring adequate frequency support is a risk to BPS reliability.


Potential Areas of Focus

• BAL Standard– Does not guarantee performance, measured by median

performance– Provides consistent methods for measuring Frequency

Response and determining the Frequency Bias Setting

• Asynchronous Resources– Modifying RS/OC Guideline to include desired operating

characteristics– Coordinating with IEEE on Standard 1547 for DER– Not currently required to have the capability to provide FR

• Planning– Frequency Response studies in the planning horizon


Variable Energy Resources StudiesOlushola J. Lutalo, MS, P.E., PMP, Senior Engineer of System AnalysisPlanning Committee Meeting, Louisville, KentuckyMarch 8, 2015


• Study the effect on the interconnection primary frequency response by replacing conventional generation with increased penetrations of of Variable Energy Resources (VERs)

• Examine scenarios of VER plant additions and Clean Power Plan (CPP) retirements impact on the Eastern Interconnection system frequency response.

Variable Energy Resource Study Objective


• Understand the reliability implications of high-level integration and penetration of VERs on primary frequency response.

• Scenarios will incorporate policy issues such as the Clean Power Plan (CPP) ruling with sensitivities focusing on high renewable penetration, control strategies, and other study assumptions.

• The VER study will use the Measure 4 metrics developed by the NERC Essential Reliability Services Task Force (ERSTF) to assess the primary frequency response.

Variable Energy Resource Study Purpose


VER Study Scenarios

VER Study Scenarios for 2021 Light LoadBusiness as usual Scenario 1 Scenario 2 Scenario 3

VER Penetration % of Total Additions for CPP Phase II Study Retirements (Coal/Oil/Gas Retirement)

Starting Case Constrained Interstate Trading

High Renewables

Nuclear retirements

VER Mix (Wind/Solar) Starting Case 50%/50% 50%/50% 50%/50%

Dispatch % of Max Output Starting Case 20-50% 20-80% 20-50%

VER Type 3/ Type 4 % Starting Case 75/25% 75/25% 75/25%

VER Frequency Control On/Off

Starting CaseOff Off Off

VER Inertia Control On/Off

Starting CaseOff Off Off


Eastern Interconnection Frequency Reponse Model of Rockport Event


NERC Modified EI Model Frequency Repsonse to Rockport Event


NERC EI Model FR of Rockport Event Compared to FNET & PMU Data

59.8

59.85

59.9

59.95

60

60.05

0 10 20 30 40 50 60

EI_FNET.F Freq Average


Phase Angle MonitoringTechnical Report Approval

Ryan D. Quint, Ph.D., P.E.Senior Engineer, System AnalysisNERC Planning Committee MeetingMarch 2016


• Purpose: Develop Technical Report on Phase Angle Monitoring and Alarming practices and experiences, and provide recommendations for future practices In response to the 2011 Pacific Southwest Outage Recommendation #27 Was a NERC SAMS task but tabled until the NERC SMS kicked off

• Topics: Phase Angle Fundamentals Finding & Recommendation 27 Synchrocheck Relay Situational Awareness EMS and PMU Application Mitigation Strategies Identifying Key Angle Differences & Correlating to System Conditions Tying Phase Angles to Oscillations & System Studies Phase Angle Monitoring Utility Practices in the West

Background


• Finding #27 “Phase Angle Difference Following Loss of Transmission Line: “A TOP did not

have tools in place to determine the phase angle difference between the two terminals of its 500 kV line after the line tripped. Yet, it informed the RC and another TOP that the line would be restored quickly, when, in fact, this could not have been accomplished.”

• Recommendation #27 “TOPs should have: (1) the tools necessary to determine phase angle

differences following the loss of lines; and (2) mitigation and operating plans for reclosing lines with large phase angle differences. TOPs should also train operators to effectively respond to phase angle differences. These plans should be developed based on the seasonal and next-day contingency analyses that address the angular differences across opened system elements.”

Finding & Recommendation #27


• Line O/S = phase angle increases (generally); impedance increases Large phase angels can lead to system instability and loss of synchronism for

generating resources

• Synchrocheck relays monitor phase angle difference across breaker terminals Reclosing line near generator with substantially large angle difference results

in large transient torque on shaft of machine – related to rotor being out of phase with BPS. Can cause instant damage or cumulative fatigue of shaft

Often used on transmission system as well

• Synchrocheck relays measure voltage magnitude difference, frequency slip, and phase angle difference between voltage Supervises against pre-determined, programmed setting prior to restoring

line to service.

The Synchrocheck Relay & Line Outages


Steady-State Monitoring & Alarming


N-1 Angle Alarming in RTCA


Visualization of RTCA Results at APS


Synchrophasor-Based Tools


• Generation redispatch Reducing generation on the sending end of the angle difference path Increasing generation on the receiving end of the path

• Use of phase-shifting transformers to reduce power flow (if available)

• Reconfiguration of system topology to reduce power flow (if possible)

• Curtailment of interruptible load, if necessary• Firm load shedding, if necessary• Point-to-point transmission service curtailment• Reconfiguration of in-series capacitors/reactors for compensation

of transmission circuits

Mitigation Strategies


Angle Limit Philosophy


Angle Differences & Oscillation Damping Ratio


• Monitoring synchrocheck contingency of interest Outage of transmission circuit and the phase angle difference across the O/S

Element exceeding synchrocheck relay limits PC and/or RC should identify key transmission circuits for this to be

monitored in real-time

• Line-based angle difference monitoring and comparison with synchrocheck relay settings can be achieved with SCADA- and/or PMU-based applications Awareness of synchrocheck relay limit exceedances should be provided to

operators for all EHV circuits with nominal voltage greater than 345 kV

• Real-time comparison of angle differences for EHV circuits and synchrocheck relay limits should be monitored using SE results. Any real-time violation of these limits for N-0 conditions should be considered

a security violation.

Recommendations


• Real-time comparison of angle differences for EHV circuits and synchrocheck relay limits should be monitored using SE results. Any real-time violation of these limits for N-0 conditions should be considered

a security violation.

• Phase angle differences for potential contingency conditions should be monitored in real-time and compared against synchrocheck relay settings for all EHV circuits using RTCA tools. Any N-1 or credible N-2 or N-1-1 exceedances (as applicable) of these limits

should be provided to the operator for advanced notice of potential line restoration issues.

Recommendations


• Wide-area angle differences provide supervisory layer of situational awareness. Can be based on transient stability, voltage stability, small signal stability, or thermal violations. Supplemental limit to conventional MW flow limits.

• Current industry standards do not explicitly require line-based angle difference monitoring and comparison to synchrocheck relay limits. Applicable NERC Reliability Standards should consider requiring real-time monitoring of phase angles and synchrocheck limit violation as a mandatory practice for RCs and TOPs.

• In the West, phase angle difference is correlated to oscillatory stability issues, particularly during high transfer conditions. Tools such as Mode Meter, Oscillation Detection, and Phase Angle Difference (PAD) should continue to be pursued for advanced situational awareness and Defense in Depth.

Recommendations


SMS Status Update



Current SMS Work Tasks

# Task Frequency Due Date1 PMU Placement Guidelines Once Q2 20162 SW Outage Recommendation 27: Angular Separation Once Q2 20163 Utilizing PMUs for NERC Reliability Standards Once Q4 20164 Model Verification Using PMUs Once Q4 20165 Technical Workshop – Power Plant Model Validation Once Q3 20166 PMUs for Cascading Outages Once Q2 20177 Monitoring IEEE C37.118 Certification Process Ongoing N/A8 Monitor Operator Training Practices Ongoing N/A9 Inter-Area Oscillation Baselining Once Q3 201710 GPS Availability Analysis – Ad-Hoc Analysis Once Q1 2016


• Task 1: PMU Placement Guideline – On Schedule (Q2 2016)• Task 2: Angular Separation Report – Complete (Q2 2016)• Task 3: PMUs for NERC Reliability Standards – Tabled (Q4 2016)• Task 4: Power Plant Model Verification using PMUs Guideline –

first approval coming next meeting – On Schedule (Q2 2016)• Task 5: Power Plant Model Verification Workshop “Save the Date” – September 20 & 21, 2016 in Atlanta, GA

• Task 6: PMUs for Cascading Outages – No Update (2017)• Task 7: Monitor IEEE Certification – Monitoring• Task 8: Monitor Operator Training Practices – No update• Task 9: Oscillation Baselining SA – Moving Along (2017)• Task 10: GPS Availability Assessment – Wrapping Up (Q1 2016)

Task Descriptions


Power Plant Model Verification

BEFORE – PSS2B Gain KS1 = 6 AFTER – PSS2B Gain KS1 = 1

ACTIVE POWER

REACTIVE POWER



BEFORE – PSS2B Gain KS1 = 6 AFTER – PSS2B Gain KS1 = 1

ACTIVE POWER

REACTIVE POWER

400

450

500

550

600

650

700

4 6 8 10 12 14

Active Power-actual Active Power-model

0

50

100

150

200

250

300

350

400

4 6 8 10 12 14

Reactive Power-actual Reactive Power-model

400

450

500

550

600

650

700

4 6 8 10 12 14

Active Power-actual Active Power-model

0

50

100

150

200

250

300

350

400

4 6 8 10 12 14


NO IMPROVEMENT



BEFORE – PSS2B Gain KS1 = 6

REACTIVE POWER

0

50

100

150

200

250

300

350

400

4 6 8 10 12 14


Required Changes to Get Fit:• Engineering judgement – NOT curve fitting• Also forced voltage regulator minimum limit to a fixed value at 2.15 pu (initializes at

2.194)• Hardcoded “workaround” for this particular event• Indicates in-plant controls that are not modeled in standard models that are impacting

plant performance as compared to modeled performance e.g., speculated phase angle rate-of-change limiter, excitation limiter Would need detailed in-plant data to actually explore in detail – still informative

0

50

100

150

200

250

300

350

400

4 6 8 10 12 14


AFTER – PSS2B Gain KS1 = 1


• Purpose/Objective: Better understand and characterize inter-area modes in each of the

interconnections (Eastern, Western, ERCOT, Quebec); Use high-resolution, time-synchronized wide-area PMU or FDR data during

major grid disturbances (and ambient conditions as needed); Identify modal characteristics (mode shape, frequency, damping ratio); Deliver a Special Reliability Assessment on this topic upon completion; Explore real-time capabilities for broader situational awareness.

• Status Update: Selected ‘dry run’ test events to collect data with SMS members; Finalizing software platform with NERC IT – streamlined, secure data

transfer Exploring data analysis tools – fundamentals and tools presentations at

NERC SMS meeting

Special Reliability Assessment:Inter-Area Oscillation Baselining


Events for Test Data Collection

EasternWestern

ERCOTSources: UTK FNET


• Understanding modal characteristics of the system are very insightful

• Characterization of inter-area modes in the Western Interconnection:

End Goal - Characterization

Sources: Montana Tech


Data Request Submittal


Data Request Submittal


Phase 2 Case Quality MetricsProposed Metrics



• Case Quality: Reasonableness of the data for individual Element models that comprise the powerflow and dynamics cases. Driven by model data only, not performance of the model (fidelity)

• Objective: perform objective analysis on interconnection-wide base cases; explore potential modeling issues we can work towards improving with MOD-032 Designees Will be engaging MOD-032 Designees shortly (once all determined) –

conference call to review Phase 1 assessment and Phase 2 metrics

• Goal: Inform PC membership; solicit feedback prior to developing automation scripts and performing analysis

Background & Goal


GENERATION• Pgen <= Pmax, Pgen >= Pmin

INTERCHANGES• Σ (Interchangescheduled) = 0CONTROL DEVICES• Vsched for actively controlling devices should not conflict• Tap step to voltage bandwidth ratio should be reasonable Flagged if TS:VB < 2; < 1.25 considered flagrant

LINES & LOADING• Rate A < Rate B and Rate B:Rate A should be less than 3• Loading < 100% Rate A; severe if loading > 105%

Phase 1 Metrics - Powerflow


GENERATORS• Generators above size threshold should have a generator model

and not be load netted EI: 20 MVA; WI: 10 MVA; ERCOT: 10 MVA

• Generators above size threshold that DO have a model BUT which are load netted. (“suspicious generators”)

• Generators above size threshold should not be modeled using classical generator model. EI: 50 MVA; WI: 0 MVA; ERCOT: 50 MVA

• Generators should have consistent reactance values (tested for GENROU and GENSAL models) Check: Xd > X’d > X’’d > Xl; Xq > X’q > X’’q

Phase 1 Metrics – Dynamics


• MBASE is not a reliable value in the base case for comparing to size thresholds Generic 100 MVA is common, particularly on small units Calculate MVA size for comparison by taking maximum of:

o 𝑃𝑃𝑔𝑔𝑔𝑔𝑔𝑔2 + 𝑄𝑄𝑔𝑔𝑔𝑔𝑔𝑔2

o 𝑃𝑃𝑚𝑚𝑚𝑚𝑚𝑚2 + 𝑄𝑄𝑚𝑚𝑚𝑚𝑚𝑚2

o MBASE unless equal to 100 MVA

• Automation scripts written for both software platforms, accounted for differences in software implementations Python for PTI PSS®E and EPCL for GE PSLF

• All powerflow cases use are “dynamics-ready” cases

Phase 1 Case Metrics ReportOther Considerations


Phase 2 Metrics Potential Metrics - Powerflow

• GENERATORS Multiple generators controlling the same bus voltage should have RMPCT

that sums to 1.0 Generators should control terminal voltage or high side of GSU Generator reactive power (Q) should not be dispatched at Qmax or Qmin if

Qmax ≠ Qmin Qmax and Qmin should have reasonable power factor compared with

Pmax – within +/- 0.85

• TRANSFORMERS Parallel transformers should have impedance within 10% of each othero Can also check for excessive circulating currents

• LOADS Individual aggregate loads should have power factor within +/- 0.5 pfo P and Q must be positive (avoid capacitor issues net generators), MVA > 2


Phase 2 Metrics Potential Metrics - Dynamics

PARAMETER ISSUES• Generator time constants should be consistent• Generator inertia constant should be within 1.5 ≤ H ≤ 9 Any H value less than 1.5 or greater than 9 is suspect

• Saturation factors S(1.0) and S(1.2) should be reasonable 0.03 ≤ S(1.0) ≤ 0.12 0.2 ≤ S(1.2) ≤ 0.8 S(1.2) should be within 2-8x S(1.0)

MODELING ISSUES• Units with a PSS but no excitation system model• Dynamic models in case but no generator modeled• Generator speed damping coefficient > 0 is flagged

𝑇𝑇𝑑𝑑𝑑" ≤ 𝑇𝑇𝑑𝑑𝑑′ 𝑇𝑇𝑞𝑞𝑑" ≤ 𝑇𝑇𝑞𝑞𝑑′



COMPONENT-BASED ISSUES• IEEEG1 & TGOV3 & WSIEG1 Lead time constants should be less than lag time constants Turbine power development fractions should add to 1.0

• GAST Should not be used in interconnection-wide dynamic cases “Really only fair for GE Frame 5 machines” – J. Undrill Working on modeling notification for this – want to see driven to 0.

Source: PSS®E Manual



• DC Exciter Models – IEEET1, IEEEET1B, IEEEX1, EXDC2, ESDC1A, ESDC2A, IEEET4, IEEEX4, IEEEET5, IEEET5A Self-excitation parameter KE reflects setting of the shunt field rheostat for

zeroing out the voltage regulator, often a small negative value KE = 0, automatically calculated by program If KE = 1, represents separately excited exciter KE should be a small negative number if not 1. Suspect otherwise.

Source: PSS®E Manual


Modeling NotificationProposed Process

Amir Najafzadeh, Senior Engineer, System AnalysisPlanning Committee MeetingMarch 8-9, 2016


Modeling NotificationOverview and Background

• Use of appropriate models that best represent machines and components within the planning arena

• NERC wide or interconnection specific• Input from software vendors, OEMs and planners• Analysis and technical background


Approval/Analysis and Posting Process

Industry/ Modeling

SMEs

• Request for analysis of modeling gaps

SAMS/MWG

• Review industry practices, available analysis• Leverage on available studies to identify benefits• Develop notification and background document

Planning Committee

• Approval and posting on NERC Website


Approval/Analysis and Posting Process Feedback Cycle

Feed

back

Tra

ck

Depending on the

Notification

GOs

TOs/ TPs

BAs/ PCs

Model Builders

Modeling NotificationsApproved by

Planning Committee

Modeling NotificationApproval/Analysis and

Posting Process

Periodic Review of Modeling Notifications


Posting of Modeling NotificationsPosting Process Upon PC Approval

• Modify the standardized component model list – if applicable• Send out NERC Announcement to Planning Coordinators,

Resource Planners, Transmission Owners, Transmission Planners, Transmission Service Provider, Balancing Authority, Generator Owner, Load Serving Entity and other applicable parties

• Feedback loop to obtain comments from the industry• Assign a review timeframe for periodic review of these models

Posting related documents on NERC-MWG webpage


Functional Model AdvisoryGroup Update

Lacey Ourso – NERC Standards DeveloperPlanning Committee MeetingMarch 8, 2016


Agenda

• Background information regarding the Functional Model (FM) and Functional Model Advisory Group (FMAG)

• 2016 FMAG project • Planning Functions • Questions for the Planning Committee


Background Information

• Purpose of the Functional Model (FM): (1) provide a framework for development of Reliability Standards, and (2) describe each function and relationships between entities responsible for

performing tasks required for each function.

• Purpose of the FMAG: (1) maintain the FM to ensure the model correctly reflects the industry

today, and (2) evaluate and incorporate new and emergent reliability-related tasks

• FMAG authority: FMAG reports to the Standards Committee and “advises and consults” with the OC, PC, and CIPC

• Revisions to the FM: FMAG to present any proposed revisions to the OC, PC and CIPC in order to “establish consensus of the technical content”


2016 FMAG project

• Current version of the FM developed in 2009 and approved by the NERC Board in 2010.

• Focus of 2016 effort: FMAG asked to review recent NERC initiatives (Risk-Based Registration

initiative) and standard development projects (Alignment of Terms) to identify any changes or updates to the FM language

Identify other changes needed as a result of new and emergent reliability-related issues


2016 FMAG project (con’t)

• Anticipated project timeline January 19-20: FMAG meeting to identify areas for focus o Planning functions (Planning Coordinator, Transmission Planner and Resource

Planner) identified as an area for revisions March 8: Inform committees (PC, OC, CIPC) of work underway, and obtain

initial feedback (specific to area of expertise) March 17-18: FMAG meeting to develop revisions to FM and Functional

Model Technical Document (FMTD) April 13-15: FMAG meeting to develop revisions to FM and FMTD June 7-8: Present FMAG proposed revisions to committees (PC, OC, CIPC) for

the purpose of “establishing consensus”


Planning Functions in the Functional Model

• Planning functions: Planning Coordinator, Transmission Planner and Resource Planner

• FMAG received industry request to review the planning functions to address perceived inconsistencies or areas of ambiguity, and also, to identify areas for improvement given how the industry has evolved since 2009 (when the FM was last revised).

• Issue: Lack of clarity regarding roles, tasks and differences between Planning Coordinator and Transmission Planner. Currently, there are a number of shared/overlapping roles and

responsibilities

• Issue: Is there a reliability gap if no Planning Coordinator exists for a particular area?


Questions

1. Do we need both Planning Coordinator and Transmission Planner functions? If yes, why? • What are the differences in the roles of the PC and TP? • Does a clear distinction between the two roles improve reliability?

2. How is the structure supposed to work? • Does the PC have an overarching coordination role?


Questions

3. How is the area of the Planning Coordinator established?

• Physically? Contractually? Asset ownership (i.e., BES Facility)?• No definition of “Planning Coordinator area” in the Glossary and

currently the FM does not address • Issues raised in by industry regarding potential reliability issues

without clear understanding of how the area is defined

4. Must there be a Planning Coordinator for every area? For every BES Facility? • Is every BES Facility required to have a TP? • Affiliated with at least one PC? • What if there are multiple PCs for one area?


Other issues or concerns?

• Should the Demand Response function (and/or entities) be added to the FM? February 2014: Report by the Functional Model Demand

Response Advisory Team (FMDRAT) • Other areas for FM revision?

http://www.nerc.com/pa/Stand/FMWG%20Scope/FMDRAT_report_approved_by_SC_on_4.9.14.pdf


Contact information

• Jim Cyrulewski (chair)[email protected]

• Jerry Rust (co-chair)[email protected]

• Lacey Ourso (NERC staff)[email protected]

mailto:[email protected]



PAS Update

Melinda Montgomery PAS ChairPlanning Committee MeetingMarch 8, 2016


• 2016 State of Reliability Report Schedule Update• Request for OC/PC reviewers

Update


• Important Dates: OC/PC review period 4/7/16 – 4/12/16 Pencils Down! (Drafting Complete) 4/19/2016 OC/PC conference call to accept 2016 SOR 5/3/2016 Send to NERC Board 5/4/2016 Present to NERC Board 5/18/2016

• The PAS requests OC and PC members to review the SOR

2016 State of Reliability Report


Unit Auxiliary Transformer Overcurrent Relay Loadability

Philip Winston, SPCS ChairNERC Planning CommitteeMarch 8-9, 2016


Background

NERC Board requested NERC staff and the PRC-025-1 standard drafting team investigate potential gaps in the standard related to UAT protective relay setting.

Standard drafting team recommended a three tiered approach:• Monitoring • Guideline• Standard


Overview

• Purpose of the report is to investigate a potential gap in UAT protective relays not applicable in the PRC-025-1 Reliability Standard; specifically, the low-side overcurrents.

• The collective experience of the NERC event analysis team participating in the SPCS, and the SPCS members, is that UAT low side phase time overcurrent protection has not operated during observed system events.


Overview

• Industry guidance on setting UAT low side phase time overcurrent protection exists and is similar to recommended settings derived in this paper. Thus, the SPCS concludes that the omission of UAT low side phase overcurrent protection from the existing NERC Reliability Standard PRC-025 standard does not pose a power system reliability risk.

• Based upon the information contained within the report, the SPCS recommends no further action.


Analysis Approachand Assumptions

• Low voltage event has occurred while the generating plant is operating under normal conditions

• Majority of UAT load consists of motor load• Motor load behavior in a depressed voltage scenario• Plant configurations with most severe impact to the UAT load

were considered


Report Findings

• The analysis identifies a minimum low voltage current pickup of the low-voltage side of UAT to prevent the overcurrent element from picking up during a depressed transmission voltage event.

• This criteria would be based on actual connected load or UAT capacity.

• This criteria assesses the worst case scenario and complements the requirements of low voltage generator ride through per PRC-024 and existing industry practices based on IEEE standards.


SAMS and MWGUpdate

John SimonelliChair, System Analysis and Modeling SubcommitteePlanning Committee MeetingMarch, 2016


SAMS Update March PC Meeting

SAMS current efforts focusing on: Developing Reliability Guideline on Reactive Power

Planning and Operations (Completion by June PC meeting)

Load Modeling Task ForceoReliability Guideline on Load Composition Data

(Expected draft complete by December 2016)

oModel Improvements – efficient data format, improved initialization, network boundary equations, model specification document (Expected complete by December 2016)

oTechnical Reference Document (FIDVR Workshop follow-up) (Expected completion by September PC meeting)



SAMS current efforts focusing on: Monitoring Plant-Level Controls and Protection

Modeling Task Force (PCPMTF) Providing technical guidance on the NERC Variable

Energy Resource (VER) Study (separate PC agenda item)



SAMS current efforts focusing on: Monitoring FAC-010/-011/-014 standards rewrite

(SDT meetings on-going)

Beginning development of study guide for high solar/wind penetration – “considerations for planning and modeling” (Early stages of development)

Began discussion on dealing with ERSTF Measure 7 on reactive resources (Further coordination with PAS)

Coordinating with NERC SMS on Power Plant Model Verification



SAMS current efforts focusing on: Develop 3φ modeling whitepaper to address more

detailed generator interactions (Southern Co taking the lead, early stages of development)

Monitoring RAS PRC-012 SDT (60.4% approval last ballot)

Monitoring IEEE 1547 rewrite – NERC Staff engaging in effort (separate PC agenda item)

Development of GMD Planning Reliability Guideline (awaiting FERC order for further action)


MWG Update March PC Meeting

MWG current efforts focusing on: Industry use of PSSE v34/PSLF v19 and node-

breaker models industry survey (MWG will finalize survey April 2016)

Procedures for Validation of Powerflow and Dynamics Caseso Still awaiting final “resting place” for document

Modeling Notifications (separate PC agenda item)


Phil Fedora, RAS Chair Planning Committee Meeting March 8-9, 2016

Reliability Assessment Subcommittee Status Update

RELIABILITY | ACCOUNTABILITY 2

•January 23rd LTRA Data & Narrative Request •Incorporation of ERS Measure 6 •Limited inclusion of Probabilistic metrics •February 19th Supplemental Data Request Hourly Load Data New Technology Integration Assessment

Reliability Assessment Subcommittee 2016 Long-Term Reliability Assessment


•Probabilistic Assessment Improvement Task Force (PAITF)

•Guideline Document •PAITF Proposed Enhancements •Probabilistic Metrics •Study Year(s)

Reliability Assessment Subcommittee 2016 Long-Term Reliability Assessment


PAITF Work Activities

Statement of Work Document Presents PAITF activities and responsibilities to improve

NERC’s ProbA reports (Approved –September, 2015)

Summary and Recommendations Report Reviews previous recommendations.

Highlights enhancements and areas of improvement. (Approved –December, 2015)

Probabilistic Assessment Guideline Document Outlines the common approaches and enhance

probabilistic assessment modeling (In development –Early Q3, 2016)


• Metric Reporting Areas • Probabilistic Study Reporting • Simulation Software • General Modeling Assumptions Load Modeling Capacity Modeling Emergency Operating Procedures Transmission Modeling Sensitivity Modeling Data Preparation and Collection

• NERC- Coordinated Regional Special Assessment

ProbA Guideline Categories


Friday, March 15, 2016 Draft Sections Due to NERC

Monday, April 4, 2016 Draft Guideline Document Due to RAS

June, 2016 Draft Guideline Document for PC Approval

Early Q3, 2016 Target Release

Remaining PAITF Timeline

The remaining milestones for the development of the Probabilistic Assessment Guideline document

2016 Long-Term Reliability Assessment Schedule

January 22nd Data and Narrative Request sent to Regional Executives and RAS

February 9th-10th RAS Meeting; Texas RE - Austin TX; Strategic Meeting

June 10 Data due to NERC

June 24 Draft Narratives due to NERC and RAS

June 29-30 RAS Meeting; Conference Call; Presentations of LTRA part 2 material

July 01 Peer Reviewer comments due to RAS

July 08 NERC to send bullet-point front section topics and ask for input from the reps

July 08 Narratives completed with all comments and responses addressed

July 12-13 RAS Meeting; SERC – Charlotte NC; LTRA Peer Review

July 22 Data and Narrative corrections or revisions due

August 01 Draft posted by NERC to RAS SharePoint

September 02 Report sent to RAS without ProbA incorporated

End of September NERC staff incorporate RAS comments

September 26-30 ProbA Team sends presentation to RAS

October 4 RAS Meeting; Conference Call; ProbA Team presents to RAS

Week of 10/17 Report sent to PC for final review

October 31 PC approves LTRA report

October 31 NERC Editorial Review

November 15-16 RAS Meeting; FRCC - Tampa FL; WRA/STSA/LTRA

November 15 NERC Executive Management Review

December 01 Report Sent to NERC Board of Trustees for Review

Early December NERC Board of Trustees Vote to Approve Report

Early December Target Release

Mid December RAS Meeting; TBD; Strategic Meeting


•February 17th Data Request •Limited Scope •Identify Summer Reliability Issues • Streamlined Process

Reliability Assessment Subcommittee 2016 Summer Reliability Assessment


2016 Summer Data Request Schedule

Deliverable Deadline

Data request sent to Regional Executives Wednesday, February 17

Data and identification/description of summer reliability issues due to NERC

Friday, April 8

RAS Meeting: Review data and identify/discuss seasonal reliability issues

Tuesday-Wednesday, April 12-13

Data review and report development Late-April – Early-May

Target release Wednesday, May 11


•Charter Review PAITF Enhancements Membership LTRA Responsibilities Operating Committee recommendations MMWG base case alignment

Reliability Assessment Subcommittee


Short-Term Special Assessment (STSA) Update

Pooja Shah, NERCPlanning Committee MeetingMarch 8-9, 2016


Introduction

• Purpose – Informational • Related Subcommittees & Groups Reliability Assessment Subcommittee (RAS) ERO-RAPA


STSA Overview

• Presented to PC - December 2015• Key Highlights NERC staff to develop topics based on inputs from various committees ERO-RAPA to prioritize the topics and provide input

• NERC Staff along with ERO-RAPA will develop the framework for the topic

• RAS to conduct assessment based on framework


1st Assessment – Natural Gas –Electric Interdependency

• Gas Availability Risk Assessment – Deterministic approach similar to Seasonal Assessment’s Operational Risk Analysis

• Near and Short – Term challenges related to Natural Gas infrastructure

• Leverage existing studies from various Assessment Areas and Regions ERCOT MISO PJM ISO-NE NYISO

• Change in report format – study outline presented in PC background material


Operational Gas Availability Risk Assessment

Identified Gas Supply Constraints

Gas-Fired Unplanned Outages (3-Year Rolling Average)

Gas-Fired Max Unplanned Outages (Extreme Weather Case)

50/50 Peak Load Forecast (Reduced by DR)

Gas-Fired Capacity

Dual-Fuel Capacity

Non-Gas-Fired


Gas-Electric STSA Schedule

Deliverable Deadline

NERC Management and RAS Review of Study Design February 1-10

Finalize Study Design and Data Template February 23

Populate Data Templates February 24-March 11

Review Data with Respective Areas March 14-25

Finalize Data with Respective Areas April 1

Ongoing Development of Report Content March 4-May 9

Report sent to Executive Management May 9

NERC Board of Trustees webinar May 23

Report Finalization and Release May 24


Pooja ShahSenior Engineer, Reliability Assessment404-446-9621 office | 404-710-0502 [email protected]


Clean Power Plan Preliminary Results

John Moura, Director, Reliability Assessment and System Analysis

Planning Committee Meeting, Louisville, Kentucky

March 8, 2016


• Formed to advise NERC on assessment scope and goals

• Representation All NERC Regions

ISO\RTOs and Planning Coordinators

IPPs and Renewable Energy Producers

Trade Organizations

Power Marketers

Consultants

Canadian Representation

• Sub-group formed to author the recommendations document

• Work with modelers to develop scenarios and assumptions

Planning Committee Advisory Group


Example of Envisioned Glide Slope

Example: Arizona

CEIP early

reductions

2020-2021

1st Interim

Period

2022-2024

2nd Interim

Period

2025-2027

3rd Interim

Period

2028-2029

1st Compliance

Period

2030-2031

Proposed 2030 Goal = 702 lb/MWh

Final 2030 Goal = 1,031 lb/MWh

Source: Salt River Project


Example of Envisioned Glide Slope

Example: Kentucky

CEIP early

reductions

2020-2021

1st Interim

Period

2022-2024

2nd Interim

Period

2025-2027

3rd Interim

Period

2028-2029

1st Compliance

Period

2030-2031

Proposed 2030 Goal = 1,918 lb/MWh

Final 2030 Goal = 1,286 lb/MWh


CPP Phase II Scenarios

• No CPPReference Case

• Intrastate trading develops, interstate constrained

Constrained Interstate Trading

• Full intrastate and interstate tradingFull Trading

• High penetration of renewablesHigh Renewables

• Accelerated retirement of nuclear unitsNuclear

retirements


lllllllllllllll

Emissions Reductions by State


0 0

(11) (10) (15)(18) (21) (22) (22) (22) (22)

(50)

(40)

(30)

(20)

(10)

0

10

150

170

190

210

230

250

270

290

310

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

CPP Retirements CPP Remaining Capacity

Coal Capacity (GW) CPP Retirements (GW)

Coal Retirements Substantially Increase under the Clean Power Plan


CPP Accelerates Coal Retirements and Gas and Renewable Builds

CAPACITY (MW) 2018 2020 2022 2025 2030

Coal 257,338 251,422 245,046 236,787 234,806

CCGT 271,615 275,228 271,644 275,493 288,178

Gas Turbine 137,735 139,027 140,485 141,790 143,833

Nuclear 101,711 103,473 104,031 104,031 104,031

Wind 93,248 99,383 116,879 126,491 141,931

Solar 21,193 25,700 30,121 36,706 54,207

TOTAL 1,091,989 1,103,401 1,116,236 1,130,279 1,176,274

Coal (414) 111 (10,708) (18,075) (22,500)

CCGT 627 1,812 7,282 5,824 (2,077)

Gas Turbine (1,042) (1,495) (1,704) (1,576) (2,697)

Nuclear - - - - -

Wind - (300) 2,100 3,300 18,300

Solar - - 150 325 400

TOTAL (958) 601 (1,380) (8,703) (6,840)

Bas

eM

ass

- C

on

stra

ined

Trad

ing


Renewables Increase with Lower Technology and O&M Costs


Remaining Uncertainties

• What will the Federal Plan look like?

• Mass versus Rate

• Parallels to previous regulations?

• Uncertainty with neighboring state plans and available transfers

• Energy efficiency expectations

• Timing and location of retirements

• Robustness of trading

• Legal impediments

• Market sensitive information sharing


• Support includes: Continuously update assessments as state plans emerge

Engage state regulators

Coordinate with Regional Entities

Distribute assessment and educational materials

Conduct annual periodic reliability assessment, multi-plan integration, and interconnection-wide analysis

ERO-Enterprise Outreach and Coordination with States on CPP


Documents

Essential Reliability Services - NERC Highlights and...annual frequency response report for all interconnections. • The FRAA establishes the Interconnection Frequency Response Obligation