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
RELIABILITY | ACCOUNTABILITY3
• December 2015 – NERC Board approved:
Framework Report Abstract Document ERS Videos
ERSTF Completion
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY8
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
RELIABILITY | ACCOUNTABILITY9
IEEE 1547 Revision Update
Ryan D. Quint, Ph.D., P.E., Senior Engineer, System AnalysisNERC Planning Committee MeetingMarch 2016
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
• 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
RELIABILITY | ACCOUNTABILITY5
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
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
RELIABILITY | ACCOUNTABILITY6
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
may ride-throughor may trip
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
range of adustability
default value
shall trip zones
may ride-through ormay trip zones
shall ride-through zonesand operating regionsdescribing performance
Based on high penetration regions (CA Rule 21, HI)
RELIABILITY | ACCOUNTABILITY7
• “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
RELIABILITY | ACCOUNTABILITY8
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
range of adustability
default value
shall trip zones
may ride-through ormay trip zones
shall ride-through zonesand operating regionsdescribing performance
may ride-throughor may trip
may ride-throughor may trip
may ride-throughor may trip
Category I, II, and III(harmonized)
299 s
299 s
60.6 Hz
may ride-through or may trip
RELIABILITY | ACCOUNTABILITY9
• 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
RELIABILITY | ACCOUNTABILITY10
• Two concepts being proposed:
Frequency-Droop Requirement
EI UFLS
RELIABILITY | ACCOUNTABILITY11
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.
RELIABILITY | ACCOUNTABILITY12
Alignment of Efforts to Maintain Adequate Frequency ResponseNERC Planning and Operating Committee MeetingSeptember 15-16, 2015
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
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**
RELIABILITY | ACCOUNTABILITY4
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.
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY7
Many Moving Parts
Frequency Response
Regulatory ActionsRS/OC Guideline
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
RELIABILITY | ACCOUNTABILITY8
Many Moving Parts
Frequency Response
Regulatory ActionsRS/OC Guideline
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
RELIABILITY | ACCOUNTABILITY9
Many Moving Parts
Frequency Response
Regulatory ActionsRS/OC Guideline
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
RELIABILITY | ACCOUNTABILITY10
Many Moving Parts
Frequency Response
Regulatory ActionsRS/OC Guideline
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
RELIABILITY | ACCOUNTABILITY11
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
RELIABILITY | ACCOUNTABILITY12
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.
RELIABILITY | ACCOUNTABILITY13
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
RELIABILITY | ACCOUNTABILITY14
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.
RELIABILITY | ACCOUNTABILITY15
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.
RELIABILITY | ACCOUNTABILITY16
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
RELIABILITY | ACCOUNTABILITY17
Variable Energy Resources StudiesOlushola J. Lutalo, MS, P.E., PMP, Senior Engineer of System AnalysisPlanning Committee Meeting, Louisville, KentuckyMarch 8, 2015
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
Eastern Interconnection Frequency Reponse Model of Rockport Event
RELIABILITY | ACCOUNTABILITY6
NERC Modified EI Model Frequency Repsonse to Rockport Event
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY8
Phase Angle MonitoringTechnical Report Approval
Ryan D. Quint, Ph.D., P.E.Senior Engineer, System AnalysisNERC Planning Committee MeetingMarch 2016
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
• 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
RELIABILITY | ACCOUNTABILITY5
Steady-State Monitoring & Alarming
RELIABILITY | ACCOUNTABILITY6
N-1 Angle Alarming in RTCA
RELIABILITY | ACCOUNTABILITY7
Visualization of RTCA Results at APS
RELIABILITY | ACCOUNTABILITY8
Synchrophasor-Based Tools
RELIABILITY | ACCOUNTABILITY9
• 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
RELIABILITY | ACCOUNTABILITY10
Angle Limit Philosophy
RELIABILITY | ACCOUNTABILITY11
Angle Differences & Oscillation Damping Ratio
RELIABILITY | ACCOUNTABILITY12
• 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
RELIABILITY | ACCOUNTABILITY13
• 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
RELIABILITY | ACCOUNTABILITY14
• 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
RELIABILITY | ACCOUNTABILITY15
SMS Status Update
Ryan D. Quint, Ph.D., P.E., Senior Engineer, System AnalysisNERC Planning Committee MeetingMarch 2016
RELIABILITY | ACCOUNTABILITY2
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
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
Power Plant Model Verification
BEFORE – PSS2B Gain KS1 = 6 AFTER – PSS2B Gain KS1 = 1
ACTIVE POWER
REACTIVE POWER
RELIABILITY | ACCOUNTABILITY5
Power Plant Model Verification
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
Reactive Power-actual Reactive Power-model
NO IMPROVEMENT
RELIABILITY | ACCOUNTABILITY6
Power Plant Model Verification
BEFORE – PSS2B Gain KS1 = 6
REACTIVE POWER
0
50
100
150
200
250
300
350
400
4 6 8 10 12 14
Reactive Power-actual Reactive Power-model
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
Reactive Power-actual Reactive Power-model
AFTER – PSS2B Gain KS1 = 1
RELIABILITY | ACCOUNTABILITY7
• 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
RELIABILITY | ACCOUNTABILITY8
Events for Test Data Collection
EasternWestern
ERCOTSources: UTK FNET
RELIABILITY | ACCOUNTABILITY9
• Understanding modal characteristics of the system are very insightful
• Characterization of inter-area modes in the Western Interconnection:
End Goal - Characterization
Sources: Montana Tech
RELIABILITY | ACCOUNTABILITY10
Data Request Submittal
RELIABILITY | ACCOUNTABILITY11
Data Request Submittal
RELIABILITY | ACCOUNTABILITY12
Phase 2 Case Quality MetricsProposed Metrics
Ryan D. Quint, Ph.D., P.E., Senior Engineer, System AnalysisNERC Planning Committee MeetingMarch 2016
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
• 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
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY7
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′
RELIABILITY | ACCOUNTABILITY8
Phase 2 Metrics Potential Metrics - Dynamics
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
RELIABILITY | ACCOUNTABILITY9
Phase 2 Metrics Potential Metrics - Dynamics
• 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
RELIABILITY | ACCOUNTABILITY10
Modeling NotificationProposed Process
Amir Najafzadeh, Senior Engineer, System AnalysisPlanning Committee MeetingMarch 8-9, 2016
RELIABILITY | ACCOUNTABILITY2
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
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY6
Functional Model AdvisoryGroup Update
Lacey Ourso – NERC Standards DeveloperPlanning Committee MeetingMarch 8, 2016
RELIABILITY | ACCOUNTABILITY2
Agenda
• Background information regarding the Functional Model (FM) and Functional Model Advisory Group (FMAG)
• 2016 FMAG project • Planning Functions • Questions for the Planning Committee
RELIABILITY | ACCOUNTABILITY3
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”
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
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”
RELIABILITY | ACCOUNTABILITY6
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?
RELIABILITY | ACCOUNTABILITY7
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?
RELIABILITY | ACCOUNTABILITY8
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?
RELIABILITY | ACCOUNTABILITY9
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?
RELIABILITY | ACCOUNTABILITY10
Contact information
• Jim Cyrulewski (chair)[email protected]
• Jerry Rust (co-chair)[email protected]
• Lacey Ourso (NERC staff)[email protected]
PAS Update
Melinda Montgomery PAS ChairPlanning Committee MeetingMarch 8, 2016
RELIABILITY | ACCOUNTABILITY2
• 2016 State of Reliability Report Schedule Update• Request for OC/PC reviewers
Update
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
Unit Auxiliary Transformer Overcurrent Relay Loadability
Philip Winston, SPCS ChairNERC Planning CommitteeMarch 8-9, 2016
RELIABILITY | ACCOUNTABILITY2
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
RELIABILITY | ACCOUNTABILITY3
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.
RELIABILITY | ACCOUNTABILITY4
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.
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY6
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.
RELIABILITY | ACCOUNTABILITY7
SAMS and MWGUpdate
John SimonelliChair, System Analysis and Modeling SubcommitteePlanning Committee MeetingMarch, 2016
RELIABILITY | ACCOUNTABILITY2
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)
RELIABILITY | ACCOUNTABILITY3
SAMS Update March 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)
RELIABILITY | ACCOUNTABILITY4
SAMS Update March PC Meeting
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
RELIABILITY | ACCOUNTABILITY5
SAMS Update March PC Meeting
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)
RELIABILITY | ACCOUNTABILITY6
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)
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY 3
•Probabilistic Assessment Improvement Task Force (PAITF)
•Guideline Document •PAITF Proposed Enhancements •Probabilistic Metrics •Study Year(s)
Reliability Assessment Subcommittee 2016 Long-Term Reliability Assessment
RELIABILITY | ACCOUNTABILITY 4
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)
RELIABILITY | ACCOUNTABILITY 5
• 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
RELIABILITY | ACCOUNTABILITY 6
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
RELIABILITY | ACCOUNTABILITY 7
•February 17th Data Request •Limited Scope •Identify Summer Reliability Issues • Streamlined Process
Reliability Assessment Subcommittee 2016 Summer Reliability Assessment
RELIABILITY | ACCOUNTABILITY1
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
RELIABILITY | ACCOUNTABILITY 8
•Charter Review PAITF Enhancements Membership LTRA Responsibilities Operating Committee recommendations MMWG base case alignment
Reliability Assessment Subcommittee
RELIABILITY | ACCOUNTABILITY 9
Short-Term Special Assessment (STSA) Update
Pooja Shah, NERCPlanning Committee MeetingMarch 8-9, 2016
RELIABILITY | ACCOUNTABILITY2
Introduction
• Purpose – Informational • Related Subcommittees & Groups Reliability Assessment Subcommittee (RAS) ERO-RAPA
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY6
lllllllllllllll
Emissions Reductions by State
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY8
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
RELIABILITY | ACCOUNTABILITY9
Renewables Increase with Lower Technology and O&M Costs
RELIABILITY | ACCOUNTABILITY10
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
RELIABILITY | ACCOUNTABILITY11
• 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
RELIABILITY | ACCOUNTABILITY12